S\/r S
r-
EVALUATION OF THE FEASIBILITY
OF TOTAL CONVERSION TO COAL FIRING
20-PLANT REPORT
PEDCo ENVIRONMENTAL
Q^
.
N
-------
PEDCo ENVIRONMENTAL
11499 CHESTER ROAD
CINCINNATI. OHIO 45246
(513) 782-47OO
EVALUATION OF THE FEASIBILITY
OF TOTAL CONVERSION TO COAL FIRING
20-PLANT REPORT
Prepared by
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
EPA Project Officer: 'Richard Atherton
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Strategies and Air Standards Division
Pollutant Strategies Branch
Research Triangle Park,
North Carolina 27711
September 24, 1978
BRANCH OFFICES
CHESTER TOWERS
Crown Center
Kansas City. Mo.
Professional Village
Chapel Hill. N.C.
-------
DISCLAIMER
This report was furnished to the U.S. Environmental Protection
Agency by PEDCo Environmental, Inc., Cincinnati, Ohio, under
Contract No. 68-02-1477. The contents of this report are repro-
duced herein as received from the contractor. The opinions,
findings, and conclusions expressed are those of the author and
not necessarily those of the U.S. Environmental Protection Agency,
11
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CONTENTS
Page
Figures vi
Tables viii
Acknowledgment xxiii
Summary xxiv
1. Introduction 1-1
2. Environmental Impacts of Coal Conversion 2-1
2.1 Direct Impacts of Coal Conversion 2-1
2.2 Measures for Reducing Direct Impacts of Coal
Conversion 2-3
2.3 Indirect Impacts of Coal Conversion 2-5
2.4 Legislation Relating to Impacts of Coal
Conversion 2-7
3. Principal Systems for Control of Emissions from
Coal Combustion 3-1
3.1 Use of Low-sulfur Coal 3-1
3.2 Flue Gas Desulfurization 3-3
4. Plant Evaluations 4-1
4.1 Arthur Kill Plant 4-1
4.2 Astoria Plant 4-18
4.3 Barrett Plant 4-35
4.4 Bergen Plant 4-50
4.5 Blue Valley Plant 4-62
(continued)
iii
-------
CONTENTS (continued)
Page
4.6 Cromby Plant 4-76
4.7 Howard M. Down Plant 4-90
4.8 Fox Lake Plant 4-103
4.9 Hudson Plant 4-116
4.10 Jones Street Plant 4-128
4.11 Lake Road Plant 4-140
4.12 Lovett Plant 4-153
4.13 Mustang Plant 4-168
4.14 Possum Point Plant 4-181
4.15 Ravenswood Plant 4-195
4.16 Ridgeland Plant 4-211
4.17 Riverton Plant 4-223
4.18 Vienna Plant 4-234
4.19 Wisdom Plant 4-247
4.20 L.D. Wright Plant 4-259
Appendices
A. Arthur Kill Plant A-l
B. Astoria Plant B-l
C. E.F. Barrett Plant C-l
D. Bergen Plant D-l
E. Blue Valley Plant E-l
(continued)
iv
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CONTENTS (continued)
Page
F. Cromby Plant F-l
G. H.M. Down Plant G-l
H. Fox Lake Plant H-l
I. Hudson Plant 1-1
J. Jones Street Plant J-l
K. Lake Road Plant K-l
L. Lovett Plant L-l
M. Mustang Plant M-l
N. Possum Point Plant N-l
0. Ravenswood Plant 0-1
P. Ridgeland Plant P-l
Q. Riverton Plant Q-l
R. Vienna Plant R-l
S. Wisdom Plant S-l
T. L.D. Wright Plant T-l
U. Basis of Sodium Solution Regenerable Process
Design U-l
V. Basis of Limestone Process Design V-l
W. ESP Support Information W-l
X. Company Letters to Federal Energy Administration X-l
v
-------
FIGURES
Number Page
4-1 Site plan of the Arthur Kill power plant 4-3
4-2 Particulate monitoring data for the Arthur
Kill power plant 4-6
4-3 Sulfur dioxide monitoring data for the Arthur
Kill power plant 4-7
4-4 Site plan of the Astoria power plant 4-20
4-5 Particulate monitoring data for the Astoria
power plant 4-24
4-6 Sulfur dioxide monitoring data for the Astoria
power plant 4-25
4-7 Site plan of the Barrett power plant 4-37
4-8 Sulfur dioxide monitoring sites for the E. F.
Barrett power plant 4-40
4-9 Site plan of the Bergen power plant . 4-52
4-10 Site plan of the Blue Valley power plant 4-64
4-11 Site plan of the Cromby power plant 4-78
4-12 Site plan of the H. M. Down power plant 4-92
4-13 Site plan of the Fox Lake power plant 4-105
4-14 Ambient sampling locations in the vicinity
of the Fox Lake power plant 4-109
4-15 Site plan of the Hudson power plant 4-118
4-16 Site plan of Jones Street power plant 4-130
4-17 Site plan of the Lake Road power plant 4-142
(continued)
vi
-------
FIGURES (continued)
Number Page
4-18 Site plan of the Lovett power plant 4-155
4-19 Sulfur dioxide monitoring sites in the vicinity
of the Lovett power plant 4-159
4-20 Site plan of the Mustang power plant 4-170
4-21 Site plan of Possum Point power plant 4-183
4-22 Ambient air monitoring stations in the vicinity
of the Possum Point power plant 4-187
4-23 Site plan of the Ravenswood power plant 4-197
4-24 Particulate monitoring data for the Ravenswood
power plant 4-201
4-25 Sulfur dioxide monitoring data for the
Ravenswood power plant 4-202
4-26 Site plan of the Ridgeland power plant 4-213
4-27 Site plan of the Riverton power plant 4-225
4-28 Site plan of the Vienna power plant 4-236
4-29 Site plan of the Wisdom power plant 4-249
4-30 Site plan of the L. D. Wright power plant 4-261
VII
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TABLES
Number Page
2-1 EPA Estimates of Uncontrolled Trace Element
Emissions from Combustion of Residual Oil
and Coal 2-2
4-1 Design and Operating Data for the Arthur Kill
Power Plant 4-2
4-2 Analysis of Fuel Burned at the Arthur Kill
Power Plant 4-4
4-3 Cost of Fuel at the Arthur Kill Power Plant 4-4
4-4 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Arthur Kill Power
Plant 4-5
4-5 Comparison of Federal and State Ambient Air
Quality Standards with the Maximum Values
Recorded Near the Arthur Kill Power Plant 4-9
4-6 Analyses of Coal Available to the Arthur Kill
Power Plant 4-10
4-7 Estimated Delivered Coal Costs for the Arthur
Kill Power Plant 4-11
4-8 Coal Conversion Data for the Arthur Kill Power
Plant 4-13
4-9 Estimated Cost of Emission Control Options at
the Arthur Kill Power Plant - 1978 4-16
4-10 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Arthur Kill Power Plant 4-17
4-11 Design and Operating Data for the Astoria
Power Plant 4-19
4-12 Analyses of Fuel Used at the Astoria Power Plant 4-21
(continued)
viii
-------
TABLES (continued)
Number Page
4-13 Costs of Fuel at the Astoria Power Plant 4-21
4-14 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Astoria Power Plant 4-22
4-15 Comparison of Federal and State Ambient Air
Quality Standards with the Maximum Values
Recorded Near the Astoria Power Plant 4-26
4-16 Analyses of Coal Available to the Astoria
Power Plant 4-27
4-17 Estimated Delivered Coal Costs for the Astoria
Power Plant 4-28
4-18 Coal Conversion Data for the Astoria Power
Plant 4-30
4-19 Estimated Costs of Emission Control Options at
the Astoria Power Plant - 1978 4-33
4-20 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Astoria Power Plant 4-34
4-21 Design and Operating Data for the E. F. Barrett
Power Plant 4-36
4-22 Analyses of Fuel Burned at the Barrett Power
Plant 4-38
4-23 Costs of Fuel at the Barrett Power Plant 4-38
4-24 Emission Rates and Applicable Regulations for
Current Fuel at the E. F. Barrett Power Plant 4-39
4-25 Comparison of Federal and State Ambient Air
Quality Standards with the Maximum Values
Recorded Near the E. F. Barrett Power Plant 4-42
(continued)
ix
-------
TABLES (continued)
Number Page
4-26 Analyses of Coal Available to the Barrett
Power Plant 4-43
4-27 Estimated Delivered Coal Costs for the Barrett
Power Plant 4-44
4-28 Coal Conversion Data for the Barrett Power
Plant 4-46
4-29 Estimated Cost of Emission Control Options at
the Barrett Power Plant - 1978 4-48
4-30 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Barrett Power Plant 4-49
4-31 Design and Operating Data on the Bergen Power
Plant 4-51
4-32 Analyses of Fuel Fired at the Bergen Power
Plant 4-53
4-33 Fuel Costs at the Bergen Power Plant 4-53
4-34 Emission Rates and Applicable Regulations for
the Bergen Power Plant when Firing Current
Fuels 4-54
4-35 Analysis of Average Coal Available to the
Bergen Power Plant 4-56
4-36 Estimated Coal Costs for the Bergen Power Plant 4-56
4-37 Coal Conversion Data for the Bergen Power Plant 4-57
4-38 Cost Assessment for Emission Controls at the
Bergen Power Plant - 1978 4-60
4-39 Emission Rates and Regulations if Recommended
Coal Conversion/Compliance Strategy Is Applied
at the Bergen Power Plant 4-61
(continued)
-------
TABLES (continued)
Number Page
4-40 Design and Operating Data for the Blue Valley
Power Plant 4-63
4-41 Analyses of Fuel Used at the Blue Valley Power
Plant 4-65
4-42 Costs of Fuel at the Blue Valley Power Plant 4-65
4-43 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Blue Valley Power
Plant 4-66
4-44 Comparison of Federal and State Ambient Air
Quality Standards with Maximum Recorded Values
Near the Blue Valley Power Plant 4-68
4-45 Analyses of Coal Available to the Blue Valley
Power Plant 4-69
4-46 Estimated Delivered Coal Costs for the Blue
Valley Power Plant 4-70
4-47 Coal Conversion Data for the Blue Valley Power
Plant 4-72
4-48 Estimated Costs of Emission Controls at the
Blue Valley Power Plant - 1978 4-74
4-49 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Blue Valley Power Plant 4-75
4-50 Design and Operating Data for the Cromby
Power Plant 4-77
4-51 Analyses of Fuel Burned at the Cromby Power
Plant 4-79
4-52 Costs of Fuel at the Cromby Power Plant 4-79
(continued)
xi
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TABLES (continued)
Number Page
4-53 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Cromby Power Plant 4-80
4-54 Federal and State Ambient Air Quality Standards
Applicable to the Cromby Power Plant 4-81
4-55 Analyses of Coal Available to the Cromby Power
Plant 4-82
4-56 Estimated Delivered Coal Costs for the Cromby
Power Plant 4-83
4-57 Coal Conversion Data for the Cromby Power Plant 4-85
4-58 Estimated Cost of Emission Control Options at
the Cromby Power Plant - 1978 4-88
4-59 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance Strategy
at the Cromby Power Plant 4-89
4-60 Design and Operating Data for the Howard M.
Down Power Plant 4-91
4-61 Analysis of Fuel Burned at the H. M. Down Power
Plant 4-93
4-62 Cost of Fuel at the H. M. Down Power Plant 4-93
4-63 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Howard M. Down
Power Plant 4-94
4-64 Comparison of Federal and State Ambient Air
Quality Standards with Maximum Values
Recorded Near the Howard M. Down Power Plant 4-96
4-65 Analyses of Coal Available to the Howard M.
Down Power Plant 4-97
(continued)
xii
-------
TABLES (continued)
Number Page
4-66 Estimated Delivered Coal Costs for the Howard
M. Down Power Plant 4-97
4-67 Coal Conversion Data for the Howard M. Down
Plant 4-99
4-68 Estimated Cost of Emission Control Options at
the Howard M. Down Power Plant - 1978 4-101
4-69 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Howard M. Down Power Plant 4-102
4-70 Design and Operating Data for the Fox Lake
Power Plant 4-104
4-71 Analyses of Fuel Used at the Fox Lake Power
Plant 4-106
4-72 Costs of Fuel at the Fox Lake Power Plant 4-106
4-73 Emission Rates and Applicable Regulations Using
Current Fuels at the Fox Lake Power Plant 4-107
4-74 Comparison of Federal and State Ambient Air
Quality Standards with Maximum Recorded Values
Near the Fox Lake Power Plant 4-110
4-75 Analysis of Available Coal for the Fox Lake
Plant 4-111
4-76 Estimated Delivered Coal Costs for the Fox Lake
Plant 4-112
4-77 Coal Conversion Data for the Fox Lake Power
Plant 4-114
4-78 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Fox Lake Power Plant 4-115
(continued)
xiii
-------
TABLES (continued)
Number Page
4-79 Design and Operating Data on the Hudson Power
Plant Boilers 4-117
4-80 Analyses of Current Fuel at the Hudson Power
Plant 4-119
4-81 Costs of Fuel at the Hudson Power Plant 4-119
4-82 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Hudson Power Plant 4-121
4-83 Analysis of Coal Available to the Hudson Power
Plant 4-122
4-84 Estimated Cost of Coal for the Hudson Power
Plant 4-122
4-85 Coal Conversion Data for the Hudson Power Plant 4-124
4-86 Assessment for Emission Control Costs at the
Hudson Power Plant - 1978 4-126
4-87 Emission Rates and Regulations if the
Recommended Coal Conversion/Compliance
Strategy Is Applied at the Hudson Power Plant 4-127
4-88 Design and Operating Data for the Jones Street
Power Plant 4-129
4-89 Analyses of Fuel Burned at the Jones Street
Power Plant 4-131
4-90 Costs of Fuel at the Jones Street Power Plant 4-131
4-91 Emission Rates and Regulations Using Current
Fuels at the Jones Street Power Plant 4-132
(continued)
xiv
-------
TABLES (continued)
Number Page
4-92 Analysis of Coal Available to the Jones Street
Power Plant 4-133
4-93 Estimated Delivered Coal Costs for the Jones
Street Power Plant 4-134
4-94 Coal Conversion Data for the Jones Street
Power Plant 4-136
4-95 Cost Assessment for Emission Controls at the
Jones Street Power Plant - 1978 4-138
4-96 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Jones Street Power Plant 4-139
4-97 Design and Operating Data for the Lake Road
Power Plant 4-141
4-98 Analyses of Fuel Used at the Lake Road Power
Plant 4-144
4-99 Costs of Fuel at the Lake Road Power Plant 4-144
4-100 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Lake Road Power
Plant 4-145
4-101 Comparison of Federal and State Ambient Air
Quality Standards Applicable to the Lake Road
Power Plant 4-146
4-102 Analyses of Available Coal for the Lake Road
Power Plant 4-148
4-103 Estimated Delivery Coal Costs for the Lake Road
Power Plant 4-149
4-104 Coal Conversion Data for the Lake Road Power
Plant 4-150
(continued)
xv
-------
TABLES (continued)
Number Page
4-105 Emission Rates and Regulations Using
Recommended Coal Conversion/Compliance
Strategy at the Lake Road Power Plant 4-152
4-106 Design and Operating Data for the Lovett Power
Plant . 4-154
4-107 Analyses of Fuel Burned at the Lovett Power
Plant 4-156
4-108 Costs of Fuel at the Lovett Power Plant 4-156
4-109 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Lovett Power Plant 4-157
4-110 Comparison of Federal and State Ambient Air
Quality Standards with Maximum Values
Recorded Near the Lovett Power Plant 4-160
4-111 Analysis of Coal Available to the Lovett Power
Plant 4-161
4-112 Estimated Delivered Coal Costs for the Lovett
Power Plant 4-162
4-113 Coal Conversion Data for the Lovett Power Plant 4-163
4-114 Estimated Costs of Emission Control Options at
the Lovett Power Plant - 1978 4-166
4-115 Emission Rates and Regulations Using the
Recommended Strategy at the Lovett Power Plant 4-167
4-116 Design and Operating Data for the Mustang Power
Plant 4-169
4-117 Analyses of Fuel Used at the Mustang Power Plant 4-171
4-118 Costs of Fuel at the Mustang Power Plant 4-171
(continued)
xvi
-------
TABLES (continued)
Number
4-119 Emission Rates and Regulations Using Current
Fuel at the Mustang Power Plant 4-173
4-120 Analyses of Available Coal for the Mustang
Power Plant 4-174
4-121 Estimated Delivered Coal Costs for the Mustang
Power Plant 4-175
4-122 Coal Conversion Data for the Mustang Power
Plant 4-177
4-123 Cost Assessment for Emission Controls at the
Mustang Power Plant 4-179
4-124 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Mustang Power Plant 4-180
4-125 Design and Operating Data for the Possum Point
Power Plant 4-182
4-126 Analysis of Fuel Fired at the Possum Point Power
Plant 4-184
4-127 Fuel Cost at the Possum Point Power Plant 4-184
4-128 Emission Rates and Regulations at the Possum
Point Power Plant when Burning Current Fuel 4-185
4-129 Comparison of Federal and State Ambient Air
Quality Standards with the Maximum Recorded
Values Near the Possum Point Power Plant 4-188
4-130 Analysis of Available Coal for the Possum Point
Power Plant 4-189
4-131 Estimated Costs of Coal for the Possum Point
Power Plant 4-189
4-132 Coal Conversion Data for the Possum Point Power
Plant 4-191
(continued) xvii
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TABLES (continued)
Number Page
4-133 Cost Assessment for Emission Controls at the
Possum Point Power Plant - 1978 4-193
4-134 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Possum Point Power Plant 4-194
4-135 Design and Operating Data for the Ravenswood
Power Plant 4-196
4-136 Analyses of Fuel Burned at the Ravenswood
Power Plant 4-198
4-137 Costs of Fuel at the Ravenswood Power Plant 4-198
4-138 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Ravenswood Power
Plant 4-199
4-139 Comparison of Federal and State Ambient Air
Quality Standards with the Maximum Values
Recorded Near the Ravenswood Power Plant 4-203
4-140 Analyses of Coal Available to the Ravenswood
Power Plant 4-204
4-141 Estimated Delivered Coal Costs for the
Ravenswood Power Plant 4-205
4-142 Coal Conversion Data for the Ravenswood Power
Plant 4-206
4-143 Estimated Costs of Emission Control Options at
the Ravenswood Power Plant - 1978 4-209
4-144 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Ravenswood Power Plant 4-210
(continued)
XVlll
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TABLES (continued)
Number Pa9e
4-145 Design and Operating Data for the Ridgeland
Power Plant 4-212
4-146 Analyses of Fuel Used at the Ridgeland Power
Plant 4-214
4-147 Costs of Fuel at the Ridgeland Power Plant 4-214
4-148 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Ridgeland Power
Plant 4-215
4-149 Analyses of Available Coal for the Ridgeland
Power Plant 4-216
4-150 Estimated Delivered Coal Costs for the Ridgeland
Power Plant 4-217
4-151 Coal Conversion Data for the Ridgeland Power
Plant 4-219
4-152 Estimated Costs of Emission Options at the
Ridgeland Power Plant - 1978 4-221
4-153 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Ridgeland Power Plant 4-222
4-154 Design and Operating Data for the Riverton
Power Plant 4-224
4-155 Analysis of Fuel Burned at the Riverton Power
Plant 4-226
4-156 Cost of Fuel at the Riverton Power Plant 4-226
4-157 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Riverton Power
Plant 4-227
(continued)
xix
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TABLES (continued)
Number Page
4-158 Analyses of Coal Available to the Riverton
Power Plant 4-228
4-159 Estimated Delivered Coal Cost for the Riverton
Power Plant 4-229
4-160 Coal Conversion Data for the Riverton Power
Plant 4-230
4-161 Cost Assessment for Emission Controls at the
Riverton Power Plant - 1978 4-232
4-162 Emission Rates and Regulations Using the
Recommended Conversion/Compliance Strategy
at the Riverton Power Plant 4-233
4-163 Design and Operating Data for the Vienna Power
Plant 4-235
4-164 Analysis of Fuel Used at the Vienna Power Plant 4-237
4-165 Cost of Fuel at the Vienna Power Plant 4-237
4-166 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Vienna Power Plant 4-238
4-167 Comparison of Federal and State Ambient Air
Quality Standards with the Maximum Recorded
Values Near the Vienna Power Plant 4-240
4-168 Analysis of Available Coal for the Vienna Power
Plant 4-241
4-169 Estimated Delivered Coal Costs for the Vienna
Power Plant 4-241
4-170 Coal Conversion Data for the Vienna Power Plant 4-243
4-171 Cost Assessment for Emission Controls at the
Vienna Power Plant - 1978 4-245
(continued)
xx
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TABLES (continued)
Number
4-172 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Vienna Power Plant 4-246
4-173 Design and Operating Data for the Wisdom
Power Plant 4-248
4-174 Analyses of Fuel Used at the Wisdom Power Plant 4-250
4-175 Cost of Fuel for Wisdom Plant 4-250
4-176 Emission Rates and Applicable Regulations for
Current Fuel Usage at the Wisdom Power Plant 4-251
4-177 Federal and State Ambient Air Quality
Standards for the Wisdom Power Plant 4-252
4-178 Analyses of Available Coal for the Wisdom
Power Plant 4-254
4-179 Estimated Delivered Coal Costs for the Wisdom
Power Plant 4-254
4-180 Coal Conversion Data for the Wisdom Power Plant 4-256
4-181 Emission Rates and Regulations Using the
Recommended Coal Conversion/Compliance
Strategy at the Wisdom Power Plant 4-258
4-182 Design and Operating Data for the L. D. Wright
Power Plant 4-260
4-183 Analyses of Fuel Used at the L. D. Wright
Power Plant 4-262
4-184 Cost of Fuels at the L. D. Wright Power Plant 4-262
4-185 Emission Rates and Applicable Regulations for
Current Fuel Usage at the L. D. Wright Power
Plant 4-263
(continued)
xxi
-------
TABLES (continued)
Number Page
4-186 Analyses of Available Coal for the L. D. Wright
Power Plant 4-265
4-187 Estimated Delivered Coal Costs for the L. D.
Wright Power Plant 4-266
4-188 Coal Conversion Data for the L. D. Wright
Power Plant 4-267
4-189 Estimated Costs of Emission Control Options at
the L. D. Wright Power Plant - 1978 4-269
4-190 Emission Rates and Regulations Using the.
Recommended Coal Conversion/Compliance
Strategy at the L. D. Wright Power Plant 4-270
xxn
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ACKNOWLEDGMENT
This report was prepared for the U.S. Environmental Protec-
tion Agency by PEDCo Environmental, Inc., Cincinnati, Ohio. The
Project Director was Mr. Timothy W. Devitt; the Project Manager,
Mr. Thomas C. Ponder, Jr. Principal investigators were David M.
Augenstein, Robert L. Hearn, N. David Noe, Douglas A. Paul,
Richard T. Price, Robert I. Smolin, Alan J. Sutherland, and
Michael F. Szabo.
Mr. Richard Atherton was Project Officer for the U.S.
Environmental Protection Agency. The authors appreciate the
assistance and cooperation extended to them by members of the
U.S. Environmental Protection Agency, the State and Local agen-
cies in Regions II, III, V, VI, and VII, and the electric util-
ities.
XXlll
-------
SUMMARY
This report involves the evaluation of 20 candidates on the
Department of Energy (DOE) list of power plants that are capable
of being converted from oil/gas firing to coal firing. Orders to
convert these plants to coal firing would affect 17 utilities in
Regions II, III, V, VI, and VII. The analyses in this report
involve the evaluation of 41 boilers for coal conversion; 38 of
which are on the DOE list.
Total fuel savings to be realized by conversion of these 38
boilers approximates 24.34 billion cubic feet of natural gas and
39.6 million barrels of oil. Total coal consumption, based on
complete conversion, is estimated to be 11.62 million tons/yr, an
increase of 11.35 million tons over the present consumption rate
of 0.27 million tons/yr. The total capital cost of complying
with applicable sulfur dioxide (S02) and particulate emission
regulations is estimated to be $763,450,000 ($115.59/kW). This
includes coal conversion costs of $112,890,000 ($17.09/kW).
Table I presents boiler and fuel data, conversion costs, and
control costs for each of the 38 boilers.
Fuel savings to be realized by conversion of the three
boilers evaluated that are not on DOE's list approximate 1.79
billion cubic feet of natural gas and 2000 barrels of fuel oil.
Estimated total coal consumption by these boilers after complete
conversion is 148,000 tons/yr, an increase of 81,000 over the
present consumption rate of 67,000 tons/yr. The total capital
cost of complying with SO- and particulate emission regulations
is estimated to be $8,830,000 ($140.16/kW). This includes coal
conversion costs of approximately $4,820,000 ($76.51/kW). Table
II presents boiler and fuel data, conversion costs, and control
costs for the three unlisted boilers.
xxiv
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TABLE I. BOILER, FUEL, AND COST DATA FOR THE
DOE CONVERSION CANDIDATES
Plant
Arthur Kill
Aatoria
E.F. Barrett
Berqen
Blue Valley
Crumby
H.N. Down
ro» Lake
Kudaon
Janet street
Lake Road
Lovett
Huatang
Poaaun Point
RavenawDod
Pidgeland
Riverton
Vienna
w I adore
L.O. Wright
Total
Boiler
No.
20
30
10
20
10
40
SO
10
1
2
}
2
10
1
1
26
27
5
6
3
4
5
1
2
J
}
4
30
1
I
)
4
5
6
1
7
1
1
JBb
Preaent fuel
Silt,
m
376
535
165
165
354
362
365
175
287
283
54
2)0
25
86
363
16
IT
27.5
103
69
196
302
CO
56
69
114
23?
800
79.5
79.5
7*.!
79.5
144
139
10
40
J8
10
6604.5
.Oil.
10s bbl/yr
2.45
2.45
1.75
0.84
1.46
1. 10
2. 83
1.43
1.62
0.95
0.01
1.22
0. 19
3.07
0.01
0.01
0.20
0.81
1. 36
0.58
0. 55
l.»7
7. 64
1. 27
1.4*
0. 60
1.11
0.0?
0.14
19.6
, Rao.
10* ft3/yr
559. }
479.7
304.3
87. J
73. 3
(69. 0
1719.1
J62.6
H85.0
8(5.0
273.0
lee. a
1284.2
5081.7
67.9
1402.6
1454.8
Z575.0
2710.0
72.9
17.6
20. 3
548.8
51.2
(60.7
771.1
24,344.4
Coal.
O3 tonVyr
80
7
41
80
43
21
272
Converted fuel
Additional
coal ,
10J tons/yr
475
772
358
208
362
502
697
322
406
400
71
299
50
118
527
14
23
58
2(1
41
243
134
111
lie
138
150
444
3)05
206
206
222
222
231
358
4
32
46
31
11. 345
iota j
Coal.
103 tons/yr
475
772
158
208
1(2
502
697
322
406
400
151
289
50
125
527
14
23
99
341
41
243
334
111
118
138
ISO
444
2505
206
20C
222
222
231
316
4
22
89
52
11.617
Capital cost"
Converaion
10s 5
10. tO
15.55
12.20
11 .36
5.19
0.06
0.21
2. It
15.08
3.8«
0
3.42
10.70
0.69
0,86
17.80
2.27
0.4S
0.14
0. 27
112.89
S/kH
11.63
11.02
81. 35
19.97
96.11
0.26
8.20
25.14
39.37
46.53
0
7.33
90.70
1.71
1 .08
21.61
SS.7S
11.13
3.79
13.50
17.09
Con t ro 1 9
106 S
87. <7
16). It
17.20
103.73
2.46
21.52
2. 14
0
46.63
6. 32
0
54. 23
4.n
21 . IB
89.08
22.02
Lit
3.15
0
2.43
i".VS6
S/kw
96.02
116.18
114.64
181 . 98
45.55
93.58
85.96
0
121.76
76,06
0
1K..46
35.27
52.54
111. 34
36.65
72.25
58.92
0
121.64
9R.SO
Totnl
1C6 5
98.07
179.49
29.41
115. LI
J.65
21. SB
2.1$
2.1<
61.71
10. ie
0
57.65
14.87
21.87
89.94
39.92
S.16
3.60
0.14
2.70
763. 45
S/kW
107.65
137. 20
195.99
201.95
141.66
43.84
94. 16
25. 14
161.1}
122.5')
0
123.79
125.97
S4.25
112.42
66.26
u?.oo
10. OS
3.79
1)5.14 —
115.55
Annual ODeratina coat
Fuel .
•illa/kwh
K.98I
(7 .73)
(10.831
(8.151
0.62
(12.54)
(5.091
4.83
110.621
2.14
0
(7.11)
11. OS
.12.24)
(5.911
(13.09)
I
(15.011
118.601
0
0.84
OtM.
milla/kWh
6.40
6. 52
3.42
5.77
0.90
8.06
2.64
0.50
4.49
9.58
0
4. 11
2.70
0.66
5.76
1.34
1«.6C
39.49
0
2.84
rixed,
milla/kwh
6.29
6.57
4 .67
10.56
1.63
5.86
3.64
a
6.90
21 . 37
0
7.16
1.97
2.10
3.94
2.10
S9.7J
11.51
0
5."0
Total
106 S
16.96
2J.90
(2. 16)
16.74
0.76
1 . on
0.11
1 .53
1 .09
1.97
0
7.01
6.72
0.92
16.74
(2). 76)
0-61
1.74
0
0.69
7*. 5*
mi lls/kwn
5.71
5. 36
12.74]
G.18
3. 15
1. 31
1. 19
5. 13
0.77
33.09
0
4.44
15.72
0.52
3.79
(9.641
«4.37
32.40
0
8.71
X
Co«t» ehovn next to each plant repreient the co«t§ for the
Total number of trailer!.
total number of bollara ihovn for that plant in the firat column.
-------
TABLE II. BOILER, FUEL, AND COST DATA FOR THE THREE
BOILERS NOT ON DOE'S LIST OF CONVERSION CANDIDATES
I'l jnt
Blue Valley
L.o. unqhi
Ton I
Bui lur
NO.
1
2
6
Sue,
m
24
24
IS
61
Present luei
Oil.
10' bbl/yc
0.001
0.001
0.001
Gas
o' It Vyr
460. 1
94». 1
J88.4
1.792.6
Coal,
10J Loiis/yt
21
30
16
61
COJ1,
10 tons/vr
21
43
17
91
|0J una//r
42
7J
JJ
148
106 5
4.61
0.11
4.62
S/kw
9(>.ll
14.00
76.il
Capital coit
10« S
2.19
1.82
4.01
5/kK
45. SS
21.14
61.65
106 5
6. BO
2.01
8.9)
5/kW
141.66
US. 14
I40.lt
Annual operating cost
Fuel .
• Uls/kwh
0.62
O.C4
OWH.
nulls/kWh
0. 90
2.84
Fixed,
nills/kWti
1.6]
5.00
Tot
I06 S
0.58
O.i2
1.20
al
mills/kwh
5. 10
8.10
X
<
H-
-------
Total projected annual emissions from the 38 boilers on
DOE's conversion list (without additional control equipment) are
309,316 tons/yr of SO- and 134,184 tons/yr of particulates. Upon
conversion, total SO- emissions would exceed the allowable limita-
tion (124,078 tons/yr) by 185,238 tons. Total particulate emis-
sions would exceed the allowable limitation (15,308 tons/yr) by
118,876 tons. Table III presents a breakdown by plant of pro-
jected annual SO2 and particulate emissions and estimated conver-
sion and compliance emissions for the 38 boilers. Table IV
presents similar data for the other three boilers evaluated.
Sulfur dioxide emissions would be four times greater and
particulate emissions nearly fourteen times greater than current
emissions if the 38 candidate boilers were converted to total
coal firing.
Sixteen plants (33 of the 38 boilers) will require addi-
tional particulate emission control if the candidate boilers are
converted to fire only coal. At least eight plants (16 of the 38
boilers) will require SO- emission control equipment, because no
available coal has a sulfur content low enough to meet applicable
State SO- regulations.
The primary potential secondary environmental impacts of
conversion are fugitive dust and water pollution. Both can be
controlled by conventional techniques.
xxvi i
-------
TABLE III. ESTIMATED CURRENT, CONVERTED, AND COMPLYING
EMISSIONS FOR DOE CONVERSION CANDIDATES
Current total annual plant emissions.
tons/yr
Plant
Arthur Kill
Astoria
E.F. Barrett
Bergen
Blue Valley
Cromby
H.M. Down
Fox Lake
Hudson
Jones Street
Lake Road
Lovett
Mustang
Possum Point
Ravenswood
Ridgeland
Riverton
Vienna
Wisdom
L.D. Wright
Total
Boiler
No.
20
30
10
20
30
40
50
10
1
2
3
2
10
3
1
26
27
5
6
3
4
5
1
2
2
3
4
30
1
2
3
4
5
6
1
7
1
7
38C
so2
Particulate
2,344 ' 412
2,339 411
1,155
Converted and complying total annual plant
emissions (coal), tons/yr
So-> Particulate
:onverteda Complying13 Converted3 Complying"
13,538
22,002
214 10,203
1
778 145
1,367
1,940
2,615
1,741
1,607
943
3,733
1,610
433
97
3,042
8
8
2,979
5,744
248
1,145
1,542
1
1
2,660
2,823
9,380
6,806
1,629
1,629
1,989
1,989
1,601
2,976
15
591
2,444
278
74,230
251
354
477
241
286
162
898
205
32
546
524
4
5,928
10,317
14,307
19,865
9,183
11,567
11,406
2,275 j 9,206
3,698 7,087
1,715 16,067
996
1,734
2,405
3,339
1,546
1,461
1,441
7,075 i 7,075
6,040
898
1,726
2,119
942
4,210
20,027 t 1,976
235
4 i 393
797
373
39
188
249
19
20
97
103
341
1,285
104
104
126
126
104
188
4
23
6
290
9,752
5,147
17,765
1,411
6,914
9,523
1,412
1,501
3,258
3,543
10,458
65,693
1,562
1,562
1,687
1,687
1,763
2,720
100
1,030
5,245
625
309,316
357
597
5,147
17,765
238
1,164
1,604
1,412
1,501
3,258
3,543
10,458
11,040
3,023
3,023
3,265
3,265
3,412
5,265
172
1,036
5,398
1,203
124,078
9,335
8,514
10,783
14,972
744
568
920
430
250
434
602
836
387
1,776 1 487
1,751 480
i
1,678 j 903
2,488 ' 350
382 , 60
9,616 ; 640
1,104
1,167
1,952
1,317
1,122
694
3,901
2,093
5,661
6,018
2,494
1,778
1,930
1,645
740
740
800
800
585
902
489
1,201
14
638
134,184
659
29
48
165
553
59
291
401
333
353
171
186
550
2,742
168
168
182
182
190
293
12
86
53
87
15,308
a Potential emissions resulting from conversion to 100 percent coal firing without the
installation of additional control equipment.
Total annual emissions allowed by State regulations.
Total number of boilers.
XXVI11
-------
TABLE IV. ESTIMATED CURRENT, CONVERTED, AND COMPLYING EMISSION RATES
FOR THE THREE BOILERS NOT ON DOE LIST
Current total annual plant emissions,
tons/yr
Plant
Blue Valley
L.D. Wright
Total
Boiler
NO.
1
2
6
so2
982
1427
209
2618
Particulate
364
531
216
1111
Converted and complying total annual plant
emissions (coal) , tons/yr
SO->
Converted3
1969
3444
465
5878
Complying13
1969
3444
906
6319
Particulate
Converted3
722
1263
480
2465
Complying0
251
439
65
755
X
X
M-
X
a Potential emissions resulting from conversion to 100 percent coal firing without the instal-
lation of additional control equipment.
Total annual emissions allowed by State regulations.
-------
SECTION 1
INTRODUCTION
The Energy Supply and Environmental Coordination Act (ESECA)
of 1974 requires that the U.S. Environmental Protection Agency
(EPA) certify all power plants that may be ordered by the Depart-
ment of Energy (DOE) to convert from firing oil or gas to firing
coal as a means of conserving limited energy resources. After
evaluating the environmental impacts of such conversion, the EPA
is to complete effective dates on the DOE conversion orders for
each plant.
The EPA Strategies and Air Standards Division contracted
PEDCo Environmental, Inc., to perform these environmental assess-
ments. The analysis of each plant first determines its compli-
ance status with respect to existing and proposed regulations for
emissions of sulfur dioxide (SO-) and particulates. The techni-
cal feasibility and potential environmental impacts of total
conversion to coal firing are considered. Because total conver-
sion could affect the plant's compliance status, the feasibility
and costs of several alternative control systems are determined.
The control alternatives considered here are use of low-sulfur
coal, flue gas desulfurization (limestone scrubbing and sodium
solution regenerable processes), and electrostatic precipitators.
Proposed locations of potential control equipment are
preliminary. A detailed engineering study would be required to
determine the most feasible locations for control equipment.
1-1
-------
Section 2 of this report summarizes the principal environ-
mental impacts of coal conversion. Section 3 presents an evalu-
ation of systems for control of emissions from coal combustion.
Section 4 presents detailed evaluations of the 20 plants con-
sidered for coal conversion. Each evaluation includes a descrip-
tion of the plant, fuel sources and characteristics, atmospheric
emissions, programs for complying with emission regulations, and
potential for fuel conversion. Methods of controlling S02 and
particulate emissions are evaluated in detail, and a recommended
compliance strategy for each plant is developed. Appendices A
through X present plant survey forms, photographs, figures and
tables pertaining to control alternatives, support information on
the flue gas desulfurization (FGD) systems and electrostatic
precipitators, and responses of utilities to inquiries of the
DOE.
1-2
-------
SECTION 2
ENVIRONMENTAL IMPACTS OF COAL CONVERSION
2.1 DIRECT IMPACTS OF COAL CONVERSION
Impacts on Air Quality
Conversion to coal firing will increase emissions of sulfur
dioxide, particulates, nitrogen oxides, hydrocarbons, and carbon
monoxide. In addition to their adverse effects on materials,
vegetation, and human health, some of these pollutants may under-
go reactions that contribute to the formation of oxidants and
sulfates in the air.
Sulfate concentrations in the ambient air have become a
matter of increasing concern in recent years, primarily because
of increasing awareness of their possible adverse health effects.
Although sulfate levels are believed to vary with levels of S02
in the air, the relationship cannot yet be quantified. Simi-
larly, the levels of sulfate that are adverse to health also
remain in question.
Conversion to coal firing can also increase the ambient
levels of a variety of toxic elements contained in the coal
(although concentrations of certain toxic trace elements, such as
vanadium, may decrease when coal is burned instead of oil). The
concentrations of these pollutants in coal are very low, and
the use of high-efficiency particulate control devices greatly
reduces their emission. Atmospheric concentrations of these
pollutants due to coal do not accumulate to levels commensurate
with known adverse health effects. The long-term effects, how-
ever, and their overall impact on human health and on the environ-
ment are not well defined. Table 2-1 presents EPA estimates of
average emissions of trace elements from oil firing and coal
firing in the United States.
2-1
-------
TABLE 2-1. EPA ESTIMATES OF UNCONTROLLED TRACE ELEMENT
EMISSIONS FROM COMBUSTION OF RESIDUAL OIL AND COALa
Pollutant
Arsenic
Beryllium
Cadmium
Manganese
Mercury
Nickel
Vanadium
Emissions, lb/10 Btu
Residual oil
0.2
0.02
1.6
0.08
0.03
14
20
Coal
1.2
1.5
0.4
0.4°
0.2
1.2
0.2
a Emission Factors for Trace Substances. EPA 450/2-73-001,
December 1973. Typical median values are presented here, as
there is a wide variation in emission rates depending on fuel
type.
b Approximately equivalent to 1590 barrels of residual oil or
400 tons of coal.
c Measured from ESP exhaust.
A final consideration with respect to impacts on air quality
is that conversion to coal firing entails potential emissions of
fugitive dust at points of transport, handling, and storage of
coal and ash. Dust emissions can occur in unloading coal and
distributing it to the storage pile. Dust can be generated in
the storage pile itself, at the transfer points of the conveyor
systems, and in the fly-ash handling system. Construction-
related activities such as movement of vehicles, transportation
of materials, alteration, and demolition are additional potential
sources of fugitive dust.
2-2
-------
Impacts on Water Resources
Conversion to coal firing could degrade water quality by
erosion and run-off at the coal burning facility and by leaching
of contaminants from coal piles or ash ponds, even with proper
treatment. Fugitive dust from exposed coal can be wind-blown
directly to surface waters or can reach water sources by indirect
routes. Hauling and handling of large tonnages of ash also
generate fugitive dust that can affect water quality similarly.
Other potential causes of adverse effects are accidental or
intentional discharge of process wastewaters, and thermal pollu-
tion from cooling water.
Impacts on Solid Wastes Management
Significant quantities of solid wastes are produced during
coal firing at a generating station. The solid waste impacts
include increased demand for landfill sites, with potential
disruption of natural wildlife, vegetation, and topography at
landfill sites, and possible contamination of local water re-
sources due to leaching from landfills. Proper disposal of ash
and treatment of wastewater prior to discharge can minimize the
adverse impacts.
Impacts on Land Use
Disposal of ash and sludge may disrupt local vegetation and
wildlife. Although such disposal sites may eventually be re-
claimed, the amount of time required and the degree of success of
reclamation efforts are not known. It is unlikely that any
reclamation program can reproduce natural topographical features
and ecological systems.
2.2 MEASURES FOR REDUCING DIRECT IMPACTS OF COAL CONVERSION
Air
Several of the principal control systems for reduction of
sulfur dioxide and particulate emissions from coal-fired boilers
2-3
-------
are discussed in detail in Section 3. This section describes
briefly some of the conventional means of controlling fugitive
dust and of reducing the adverse impacts of water pollutants and
solid wastes resulting from conversion to coal. These control
measures are considered specifically with reference to the 20
power plants in later portions of the report.
It appears that the most cost-effective method of control-
ling dust emissions from coal handling operations is the use of
water sprays that incorporate a wetting agent such as calcium
chloride. At plants that unload coal by rail car or barge, these
sprays could be used at the coal-car shaker, the barge unloading
point, the conveyor transfer points, and the stack reclaimer.
The water could be plant wastewater with a wetting agent added.
At most power plants the coal conveyors are enclosed, and the
dust could be controlled by adding only a small amount of water.
The coal storage pile can also be a problem when coal is removed,
especially in windy conditions. This dust can be suppressed by
use of windbreaks and water sprays.
Fugitive dust emissions from fly-ash handling can be con-
trolled by keeping the ash wet through all handling operations.
This can be accomplished by using water sprays or by sluicing the
ash to the pond.
Adequate control means are available for the 20 conversion
candidates to be able to comply with State fugitive dust regula-
tions when firing coal.
Water
Proper handling of the coal ash at power plants can greatly
reduce adverse impacts on water quality. Discharges into ground-
water can be prevented or minimized by lining the coal pile and
ash/sludge disposal sites with impermeable clay or other lining
material. Sludges from FGD scrubbers can also be chemically
fixed to promote better settling characteristics and allow possi-
ble land reclamation. Runoff from disposal sites can be collected
and treated to reduce levels of suspended solids, acidity, and
heavy metals content.
2-4
-------
Solid Wastes
Generation of coal ash can be minimized by using a relatively
low-ash coal or by cleaning high-ash coal, although the cleaning
process also produces solid wastes.
Some utilities have been able to find markets for coal ash
(as a construction material). In Japan, FGD scrubber sludges
have been oxidized to long-fiber gypsum for wallboard production.
Unfortunately, this type of technology has not been applied in
the United States because economic incentives have been inadequate,
Another way to reduce solid wastes from scrubber operations
is to use a regenerable S02 scrubbing system having elemental
sulfur or sulfuric acid as an end product. A market for the end
product is required, of course, for the regenerable process to
compete with a throwaway scrubber system, such as limestone.
Land Use
The adverse impacts of ash disposal on land use can be
minimized by (1) selection of a disposal site that allows dis-
posal of ash or sludge at a significant depth to reduce required
acreage; (2) by selection of a site without sensitive species or
habitats; and (3) by revegetation and reclamation of disposal
areas when their use is completed.
2.3 INDIRECT IMPACTS OF COAL CONVERSION
Indirect Impacts on Air Quality
Increases in domestic production of coal will unavoidably
produce increased emissions of combustion-related pollutants from
power equipment and increased levels of fugitive dust in areas
where coal processing and transport occur. Emissions from power
equipment are generally uncontrolled and relatively insignificant.
2-5
-------
Fugitive dust control is the same as that for construction-
related activities, i.e., frequent watering and use of chemical
suppressants.
Indirect Impacts on Water Resources
Unavoidable indirect adverse impacts on water systems in-
clude interruption of aquifers during mining, depletion of water
resources, increased evaporation of water during coal processing
and ash or sludge ponding, and diversion of water supplies from
alternative uses (agriculture, recreation, fish habitat).
Indirect Impacts on Solid Waste Management
Large quantities of solid wastes are produced during coal
extraction; the resulting environmental impacts are the same as
those produced directly by coal firing, i.e., use of acreage for
landfill, disruption of natural features (including wildlife),
and possible contamination of waters.
Indirect Impacts on Land Use and Ecology
Vegetation and wildlife in undeveloped areas are disrupted
or destroyed during the development of coal mines, processing
facilities, transport systems, and solid waste disposal sites.
In developed areas, land is converted from other uses (agricul-
ture, housing, recreation) to uses serving coal production and
utilization. Land use is permanently disrupted or altered when
permanent facilities are developed for coal transport and proces-
sing. Other areas used in mining and solid waste disposal may
eventually be reclaimed, although to what extent and how success-
fully is not yet known.
Commitment of Resources
In addition to direct and indirect environmental impacts,
and coal conversion program entails some irreversible and irre-
trievable commitments of resources. Obviously, mineral resources,
See: Investigation of Fugitive Dust, Vol. I, Sources, Emis-
sions and Controls, EPA 450/3-74-036a.
2-6
-------
are affected by the increase in coal demand. Water resources
also are diminished, and some of the productivity of lands may be
lost permanently or long term.
Other significant resource commitments include affected
specimens of archaeological or paleontological value and altera-
tions to the natural state of a region that reduce aesthetic
value. Fatal accidents that occur in mining also must be con-
sidered as irretrievable losses of human resources. Further, the
manpower, machinery, and fuels needed to extract the coal must be
considered as irretrievably committed.
2.4 LEGISLATION RELATING TO IMPACTS OF COAL CONVERSION
Air Quality
Air quality impacts are addressed in regulations at all
levels of government: city, county, State, and Federal. The
Federal regulations applicable to both direct and indirect air
impacts from coal conversion are listed below:
0 Clean Air Act of 1970
0 National Ambient Air Quality Standards
0 New Source Performance Standards
0 National Emissions Standards for Hazardous Air Pollu-
tants
The National Ambient Air Quality Standards for sulfur dioxide,
particulates, and nitrogen oxides are most pertinent to this
analysis. Each State is required by the Clean Air Act to compile
a State Implementation Plan as the basis for regulating air
pollutants sufficiently to attain or maintain National Ambient
Air Quality Standards. In addition, certain metropolitan areas
have rules and regulations pertaining to air quality. All local
standards must at least ensure attainment of the National Ambient
Air Quality Standards. Section 3 of ESECA, by amending the Clean
Air Act, sets forth Federal, State, and local law and policies
concerning air quality and the coal conversion program.
2-7
-------
Water Resources
Water quality impacts are also addressed at all governmental
levels. The Federal Water Pollution Control Act Amendments of
1972 serve as a basis. This act was designed to reduce the
cumulative effects of regional development on water quality. The
Safe Drinking Water Act is also pertinent. The Federal Govern-
ment has recommended different standards for drinking water,
irrigation water, and water for recreational uses, all of which
are intended to mitigate adverse impacts^ Each State has similar
standards.
Because large amounts of water are consumed in coal mining,
water supply is also an important concern. The Federal Water
Resources Planning Act of 1964 was designed to encourage conser-
vation or utilization of water-related resources on a comprehen-
sive and coordinated basis at all levels of government. Under
this legislation, regional or river basin plans are prepared to
resolve problems of competing use. In addition to this Federal
legislation establishing River Basin commissions, most States
have intra- and interstate laws concerning competing or priority
water uses.
Land Resources
The Solid Waste Disposal Act does not set standards in the
same way as the air and water acts cited previously. Although
guidelines and information are issued at the Federal level, the
major responsibility for the manner of disposal of solid wastes
rests at the State or local levels. The situation with respect
to land-use regulations is much the same.
Land is significantly disturbed by mining and by construc-
tion of pipelines and roads. Federal authority to mitigate
adverse impacts is embodied in several of the following laws and
pursuant regulations: Mineral Leasing Act, Mineral Leasing Act
for Acquired Lands, Interstate Commerce Acts, and Multiple-use
2-8
-------
Sustained-yield Act of 1960. One of the goals of the Mining
Operating Regulations issued in 1973 by the Department of the
Interior is to promote operating practices that prevent, mini-
mize, or correct damage to air, water, and land environments.
Many States in which mining is practiced have issued land-quality
regulations.
2-9
-------
SECTION 3
PRINCIPAL SYSTEMS FOR CONTROL OF EMISSIONS FROM COAL COMBUSTION
3.1 USE OF LOW-SULFUR COAL
The naturally occurring low-sulfur coals are anthracite,
low-sulfur western bituminous, and eastern bituminous coal.
Except for anthracite coal, which is difficult to burn in systems
designed for bituminous coal, eastern utilities encounter no
major furnace/boiler problems when switching to a low-sulfur
eastern coal.
The most abundant source of low-sulfur fuel is western
subbituminous coal. Most of the reserves of this coal are suf-
ficiently low in sulfur and high in heat content for use as an
acceptable low-sulfur fuel by current definitions. Western
subbituminous coal is found chiefly in Wyoming and Montana.
Sulfur content ranges from 0.3 to 1.5 percent, and heat content
from 8200 to 10,500 Btu (moisture- and ash-free).
In conversion of a steam-generating unit from one source of
coal to another, the physical and chemical properties of the coal
are of particular interest with respect to operating character-
istics and possible furnace/boiler problems. Analysis of coal
samples forms the basis for judgment and engineering calculations
Conversion from one type of coal to another usually causes
significant changes in operating characteristics only when there
are marked changes in the physical and chemical properties of the
coal. Some of the possible effects on boilers and other plant
equipment are listed below:
3-1
-------
1. The quantity of fuel required to sustain a given
output depends on heating value. Converting to western
fuels generally requires use of more coal and may
require additional pulverizer and primary air system
capability.
2. Boiler efficiency is related to the moisture and
heating value of the fuel, and to changes in weight of
the gas produced by combustion. Converting to western
coal generally reduces furnace/boiler efficiency.
3. Coals with high moisture content and low heating value
produce heavy flue gas resulting in increased gas
velocity and loss of draft in the convection passes.
Fan power and capacity requirements will also be higher.
4. Superheater steam temperatures increase with increases
in flue gas weight and temperature. Boilers with
radiant superheaters in the furnace and convection
superheaters in the gas pass are affected by conversion
to coals that produce more furnace slagging by reduc-
tion of heat absorption in the lower furnace and in-
creased heat absorption in the upper furnace. Higher
steam temperatures and metal temperatures occur in both
radiant and convection superheaters, with a correspond-
ing increase in steam temperature control duty.
Adjustment to heating surface may be required.
5. Additional fuel and ash handling and storage facilities
may be required if tonnages are significantly different
from those now handled.
Full-scale combustion testing is the most reliable method of
evaluating coal from a new source. Prediction of combustion
performance and associated problems by laboratory tests is costly
and requires expert data evaluation; since most of the tests are
empirical and the results rely on statistical correlations, data
from these tests are at best indicative rather than conclusive.
Full-scale combustion testing over a minimum 1-week period,
together with appropriate laboratory testing, is the best pro-
cedure for evaluating a new coal source. Even the short-term,
full-scale test may not disclose all combustion problems, since
some ash deposition occurs only after a significant (up to
several months) conditioning period.
3-2
-------
In practice, when considering a new coal source most utility
consumers rely heavily on their own boiler operating experience,
the experience of others with similar coals, and recommendations
from vendors of combustion equipment.
3.2 FLUE GAS DESULFURIZATION
The FGD systems evaluated in this report are the sodium
solution regenerable and limestone processes. The sodium solu-
tion system is an example of a regenerative system, and the
limestone process is representative of a throwaway system.
Sodium Solution Regenerable Process
The sodium solution regenerable SC>2 recovery system, illus-
trated in Figure U-l, Appendix U, is based on the ability of an
aqueous solution of sodium sulfite/bisulfite to react with S02 at
relatively low temperatures and to release it when subjected to
higher temperatures. No waste slurry is generated.
Flue gas from the boiler enters the absorber tower near the
base, where it is quenched with water to cool it before it ascends
through the absorption section of the tower. The absorber con-
tains two stages where the ascending flue gas is brought into
contact with the aqueous solution of sodium sulfite/bisulfite.
The lean sodium sulfite is fed into the tower near the top and
flows downward, passing through each stage countercurrent to the
flow of the gas. As SO- is absorbed in the solution, the sodium
sulfite is converted to sodium bisulfite, which increases the
capacity of the solution for absorbing SO-.
The scrubber flue gas leaves the absorber, passes through a
mist eliminator, and is reheated before discharge to the atmo-
sphere. A booster fan is used to overcome the pressure drop in
the scrubbing system. The absorber removes approximately 85
percent of the SO in the flue gas.
To prevent buildup of sodium bisulfite, the solution is
discharged from the base of the absorption section of the tower
3-3
-------
into a storage tank. Use of this tank and a companion sodium
sulfite storage tank permits regulation of the feed. The tanks
also provide sufficient surge capacity to allow the absorber to
operate independently of the rest of the process.
From the storage tank the solution enters an evaporator,
where low-pressure steam heats it, driving off SG>2 and water
vapor. Sodium sulfite is precipitated, and a dense slurry of
crystals is generated. To reduce the amount of steam used,
double-effect evaporators are used. The overhead from the first
evaporator condenses in the reboiler of the second evaporator.
The overhead from the second evaporator and the noncondensable
fractions from the first evaporator are passed through a partial
condenser.
The S0_/water mixture from the partial condenser is recti-
fied in a stripper. The overhead from the stripper passes through
another partial condenser to remove the aqueous phase. The
noncondensables from this condenser, which contain about 90
percent S0_ by weight (10% water vapor), are further processed to
recover either sulfuric acid or sulfur. Condensates from the
reboiler, the stripper bottoms, and fresh makeup water are used
to redissolve the sodium sulfite crystals in a dissolving tank.
The solution, primarily sodium sulfite, is pumped from the dis-
solving tank to the sulfite storage tank.
To prevent buildup of sodium sulfate and other inert mate-
rials such as fly ash, some of the liquid leaving the absorber is
purged from the system. This purge stream is chilled to precipi-
tate the sodium sulfate crystals. The crystals and fly ash are
separated in a centrifuge, washed, and dried. The treated purge
stream is then recycled to the system. Caustic soda or soda ash
is added to replenish the sodium lost in the purge stream.
The process design basis for the sodium solution regenerable
system is presented in Appendix U.
3-4
-------
Wet Limestone Scrubbing Process
The limestone scrubbing system illustrated in Figure
V-l, Appendix V, utilizes a slurry of ground limestone (CaCO.,)
and water as the S02 absorbing medium. The S02 reacts with the
limestone to form calcium sulfite (CaSO-,) , which is removed from
the system as a waste product. A booster fan is used to overcome
the pressure drop in the system.
Flue gases from the boiler enter an absorption tower near
the base, where quenching with water reduces the temperature of
the gases before they ascend through the absorption section of
the tower. The ascending flue gases are brought into contact
with the limestone slurry in two stages. Concentration of solids
in the slurry range from 4 to 15 percent. Sulfur dioxide removal
efficiencies are usually 85 percent or greater.
The scrubbed flue gases pass through a mist eliminator and
are then reheated prior to discharge to the atmosphere. Reheat-
ing of flue gases increases dispersion and raises the gas temper-
ature far enough above the dew point to prevent excessive con-
densation.
The limestone system entails handling and conveying equip-
ment, storage silos, and slurry storage tanks.
Partial recovery of water is achieved through solid/liquid
separation operations. The slurry leaving the absorber goes to
the absorber circulation tank, where hydrated CaSCU and CaSO.
crystals precipitate. A bleed stream containing these solids is
sent to a gravity clarifier, where the crystals, fly ash, and
unreacted limestone settle. The overflow from the clarifier and
the filtrate are returned to the circulation tank. The underflow
from the clarifier is filtered to produce a sludge with a mois-
ture content of about 60 percent. The sludge is treated by
addition of fixation chemicals in a mixing tank to prevent sub-
sequent leaching and is then trucked to a permanent disposal site.
The treated or "fixed" sludge forms a stabilized fill material
that can support vegetation and subsequent development. The
design rationale used in this study is presented in Appendix V.
3-5
-------
SECTION 4
PLANT EVALUATIONS
4.1 ARTHUR KILL PLANT
4.1.1 Plant Description
The Arthur Kill plant (owned and operated by the Consoli-
dated Edison Company of New York) is located on the east bank of
the Arthur Kill River on Staten Island in New York City in Rich-
mond County. This area is part of the New Jersey/New York/Con-
necticut Interstate Air Quality Control Region (AQCR 043).
The two boilers at the Arthur Kill plant are evaluated for
conversion to coal firing. Boilers 20 and 30 were placed in
service in 1959 and 1969, respectively, and have maximum contin-
uous generating capacities of 376 and 535 MW. The boilers ex-
haust through a common 518-ft stack. Boilers 20 and 30 origi-
nally were designed to fire coal, but later were converted to
fire oil, which they currently fire. Boiler 20, manufactured by
Babcock and Wilcox, is equipped with a mechanical collector and
an electrostatic precipitator (ESP); Boiler 30, manufactured by
Combustion Engineering, is equipped with an ESP only. Additional
unit design and operating data are presented in Table 4-1. A
plant site plan is shown in Figure 4-1.
4.1.2 Fuel Supply and Characteristics
Boilers 20 and 30 currently fire oil. Boiler 20 has not
fired coal since 1969; Boiler 30 fired a small amount of coal in
1974 because of the oil embargo. In 1975 the plant fired 4,897,000
bbl of oil. The oil was purchased from a tank farm, where oil is
distributed from various suppliers. The latest available fuel
oil analysis and cost are presented in Tables 4-2 and 4-3, re-
spectively.
ARTHUR KILL POWER PLANT 4-1
-------
TABLE 4-1. DESIGN AND OPERATING DATA FOR THE ARTHUR KILL POWER PLANT
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input,0 106 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
Coal firing
20
376
7289
33.9
2
B&W
1959
120
2880
518
1,400,000
300
Mechanical
collector
and ESP
30
535
5345
39.5
2
CE
1969
171
4104
518
1,560,000
293
ESP
EG
G
f
f
o
s:
w
f
>
2
a Information from Power Plant Survey Form (Appendix A).
B&W - Babcock & Wilcox; CE - Combustion Engineering.
0 Based on coal heating value of 12,000 Btu/lb.
I
to
-------
Figure 4-1. Site plan of the Arthur Kill power plant.
-------
TABLE 4-2. ANALYSIS OF FUEL BURNED AT THE
ARTHUR KILL POWER PLANT
Analysis
Heating value
Sulfur
Fuel oil
144,224 Btu/gal
0.29%
Information from Power Plant Survey Form (Appendix A).
TABLE 4-3. COST OF FUEL AT THE ARTHUR KILL POWER PLANT
Type of purchase
Contract
Fuel oil cost,3 ?/106 Btu
2.141
Information from Electrical Week magazine, May 1, 1978.
4.1.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 043
as Priority I with respect to emissions of particulates and
sulfur oxides. Part 227.3 (c) of the New York Regulations limits
particulate emissions from oil or coal firing in Boilers 20 and
30 to 0.10 lb/10 Btu heat input. The regulations under Part
225, Table I, limit the sulfur content in residual oil to 0.30
percent and the S02 emissions from coal firing to 0.40 lb/10
Btu. Table 4-4 summarizes emission rates and applicable regula-
tions for the Arthur Kill plant.
AJr Quality Monitoring Data —
From July 1973 through June 1974, ambient particulate and
S02 monitoring data were collected at six stations in Richmond
County. These data were used to characterize the ambient air
quality in the vicinity of the Arthur Kill power plant. Figures
4-2 and 4-3 show the six monitoring stations and the maximum
values recorded at each station during the 1-year period.
The City of New York, Dept. of Air Resources, Bureau of Techni-
cal Service. Fiscal Report, July 1, 1973 - June 30, 1974.
ARTHUR KILL POWER PLANT 4-4
-------
50
H
ac
c
50
TABLE 4-4. EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT
FUEL USAGE AT THE ARTHUR KILL POWER PLANT
i
M
50
Fuel type
Boiler 20
Current fuel
Oil
Boiler 30
Current fuel
Oil
Sulfur dioxide
Actual a
emission rate
Lb/106 Btu
0. 32
0.32
tons/yr"
2344
2339
Al lowable
emission rate
Ib/lflS Btuc
0.33
0.33
, D
tons/yr
2424
2419
Particulate
Actual
emission rate .
lb/106 Btu
0.06
0.06
tons/yr
412
411
Allowable
emission rate ,
lb/106 Btu
0.10
0.10
tons/yi"
686
685
Based on AP-42 emission factors and an oil analysis of 0.29% S and 144,224 Btu/gal.
Based on 1975 fuel consumption.
Based on AP-42 emission factors and an allowable oil sulfur content of 0.3% S (144,224 Btu/gal).
I
U1
-------
NEW JERSEY
GOETHALS BRIOG1
NEW YORK
n
FRESH KILLS 178
74
TOTTENSVILLE H_.S.;*:
MANUAL STATION
TELEMETRY STATION
Figure 4-2. Particulate monitoring data for the
Arthur Kill power plant.
Upper number: maximum 24-hour average, yg/m
Lower number: annual geometric mean, yg/mj
ARTHUR KILL POWER PLANT
4-6
-------
NEW JERSEY
156 iE*LH-sV/- LOWER BAY
72 \
NEW YORK
SEAVIEH HOSPITAL
n A
43 RICHMOND CO.
MANUAL STATION
TELEMETRY STATION
Figure 4-3. Sulfur dioxide monitoring data for the
Arthur Kill power plant.
Upper number: maximum 24-hour average, yg/m
Lower number: annual average,
ARTHUR KILL POWER PLANT
4-7
-------
Measurements indicate that the annual geometric mean stan-
dard for particulates was violated at all six stations. Four of
the stations recorded values that violated the Federal primary
standard. The Federal and State secondary standards were vio-
lated at all six stations. The maximum annual geometric mean
concentration of 105 yg/m was recorded at the Fresh Kills sta-
tion. Construction that was started in May 1974 near this
station could have significantly increased the particulate level.
The next highest geometric mean of 88 pg/m was recorded at the
Borough Hall station.
The 24-hour particulate standard also was violated at all
of the stations. The Fresh Kills station recorded a value of 263
pg/m , which violated the Federal primary standard. (The con-
struction nearby may have caused the high reading.) The maximum
values recorded at the other stations violated the Federal sec-
ondary standard. The second highest value recorded in Richmond
County was 230 pg/m , measured at the Goethals Bridge station.
No Federal or State SCU standards were violated at any of
the six monitoring stations during the July 1973 through June
1974 period. The maximum recorded annual average and 24-hour
3 3
values were 72 pg/m and 235 pq/m , respectively. The Seaview
Hospital monitor recorded the maximum annual average, and the
Borough Hall and Tottensville High School monitors recorded the
24-hour maximum.
Table 4-5 summarizes the Federal and State ambient air
quality standards and maximum concentrations recorded in the
Richmond County area.
4.1.4 Plant Programs for Complying with Emission Regulations
When Boilers 20 and 30 fire oil, they comply with New York
particulate and S02 emission standards. The plant has formulated
no plans for compliance in the event it is ordered to switch to
coal firing.
ARTHUR KILL POWER PLANT 4-8
-------
TABLE 4-5. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
WITH THE MAXIMUM VALUES RECORDED NEAR THE ARTHUR KILL POWER PLANT
(Concentration in y.g/m )
so2
Annual average
Maximum 24-hour average
Particulate
Annual geometric mean
Maximum 2 4 -hour average
Ambient air quality standards
Federal
Primary
80
365
75
260
Secondary
60
150
State
Primary
80
365
65
250
Secondary
Maximum
recorded
values
72
235
105a
263b
i
w
50
f
i-3
The second highest value was 88.
The second highest value was 230.
-------
4.1.5 Analysis of Coal Conversion Potential
Coal Availability —
Coal could be obtained from western and central Pennsylvania
(Producing Districts 1 and 2) and southern West Virginia and
eastern Kentucky (Producing Districts 7 and 8). Both areas
currently have a surplus of coal. If market conditions warrant
the need for the development of new mines, a minimum of 2 years
would be necessary before initial supplies could be available.
Table 4-6 shows general characteristics of available coal
sources for the Arthur Kill plant.
TABLE 4-6. ANALYSES OF COAL AVAILABLE TO THE
ARTHUR KILL POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Western/central
Pennsylvania
12,000 - 12,500
2.0 - 2.5
9-15
Southern West Virginia and
eastern Kentucky
12,000
1.0
6
- 12,500
- 1.5
- 12
Coal produced in central Pennsylvania would be loaded onto
the Consolidated Rail Corporation (ConRail) rail lines and then
transferred to the Staten Island Rapid Transit (SIRT) rail lines
near Bound Brook, New York, for delivery to the Arthur Kill
plant. Coal produced in the southern West Virginia and eastern
Kentucky area would be loaded onto the Chessie System, and then
transferred to SIRT for final delivery.
Foster Associates, Inc. Present and Prospective Coal Supply to
the Arthur Kill, Astoria, and Ravenswood Plants - Consolidated
Edison Company of New York, Inc. September 9, 1976.
ARTHUR KILL POWER PLANT
4-10
-------
Both rail carriers have indicated that no major problems
would be involved in transporting coal to the Arthur Kill plant.
ConRail has no hopper cars on order; however, it has leased 1100
additional hopper cars and has instituted a locomotive and hopper
car rehabilitation program to reduce scheduling problems in coal
traffic. Speeds are limited to 30 mph on deteriorated sections
of the former Penn Central main and branch lines. ConRail per-
sonnel have indicated that funds are now available for upgrading
the deteriorated lines, and repairs are underway. The Chessie
System has adequate capacity to transfer additional coal. In
1976, Chessie had plans to install about 7000 new and rebuilt
hopper cars.
Table 4-7 shows delivered costs of coal produced in the
central Pennsylvania and the southern West Virginia - eastern
Kentucky areas. Mine prices (f.o.b.) are representative of
current quotations for contract purchases. Transportation costn
include single-car tariffs now in effect. Volume tariffs prob-
ably could be negotiated if the boilers are converted to coal
firing.
TABLE 4-7. ESTIMATED DELIVERED COAL COSTS FOR THE
ARTHUR KILL POWER PLANT
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/106 Btu
Central
Pennsylvania
19.00
10.25
29.25
1.170a
1.289a'C
Eastern
Kentucky
18.25
12.89
31.14
1.298b
1.430b'C
Based on a coal with a heating value of 12,500 Btu/lb.
Based on a coal with a heating value of 12,000 Btu/lb.
Foster Associates values escalated to 1978 dollars.
ARTHUR KILL POWER PLANT
4-11
-------
Technical Factors Affecting Fuel Conversion--
If Boilers 20 and 30 are ordered to convert to coal firing,
both units would require the refurbishing of coal and ash han-
dling equipment. The fly ash, raw coal, and pulverizer systems
would have to be overhauled on both boilers. In addition, a new
bottom ash system and fly ash storage facility must be installed
on Boiler 20, and the burner equipment and controls must be
overhauled. The bottom (furnace) on Boiler 30 must be converted
to fire coal, and the orifices and combustion and burner controls
also must be changed. A new wastewater treatment system must be
installed before the plant converts to coal firing. Cost of
restoring and/or replacing the equipment on both boilers is
estimated to be $10,597,000 (1978 dollars), based on Consolidated
Edison's letter to the FEA. Coal conversion data are presented
in Table 4-8.
4.1.6 Analysis of Methods for Controlling SC^ Emissions
Low-sulfur Coal--
Coal having an analysis of approximately 0.25 percent sulfur
and 12,000 Btu/lb would be necessary to meet the New York SO
g 2
emission regulation of 0.40 lb/10 Btu. Coal of this analysis is
not available to the Arthur Kill plant.
Flue Gas Desulfurization (FGD)—
A sodium solution regenerable and a limestone scrubbing
system are evaluated for control of S02 emissions at the Arthur
Kill plant. The systems are based on firing coal having charac-
teristics representative of Producing District 8; they would
require approximately 84 percent removal capability to meet the
0.40 lb/106 Btu S02 regulation.
The estimated capital cost of retrofitting Boilers 20 and 30
with a sodium solution regenerable system is $121,642,000 ($133.53/
kW), including the coal conversion cost of $10,597,000. The
annual operating cost, including a fuel credit (in switching from
oil firing to coal firing), is estimated to be $14,549,000
ARTHUR KILL POWER PLANT 4-12
-------
TABLE 4-8. COAL CONVERSION DATA FOR THE ARTHUR KILL POWER PLANT
Boiler
No.
20
30
Total
Capacity
factor
(1975) ,
%
33.9
39.5
Fuel consumption3
Type
Oil
Oil
bbl/yr
2,451,200
2,445,800
Coal conversion data K
Conv. cost,
$
10,597,000
Coal usage, ~
tons/yr
475,000
772,000
1,247,000
as
c
f
f
o
M
f
"-3
1975 consumption figures.
Estimated tonnage required for conversion to total coal firing, based on coal
heat rates.
-------
(4.90 mills/kWh). The estimated capital cost of retrofitting
Boilers 20 and 30 with a limestone scrubbing system is $98,069,000
($107.65/kW), including the coal conversion cost. The annual
operating cost, including the fuel credit, is estimated to be
$16,963,000 (5.71 mills/kWh).
Costs of the sodium solution regenerable and limestone
scrubbing systems are represented in January 1978 dollars and are
not escalated through project completion.
4.1.7 Analysis of Methods for Controlling Particulate Emissions
Boiler 20 is equipped with a mechanical collector and an ESP
(manufactured by Research Cottrell) that have a combined design
efficiency of 99 percent. Boiler 30 is equipped with an ESP
(manufactured by American Standard) that has a design efficiency
of 99.5 percent. The ESP's have deteriorated, however, especially
on Boiler 20, and their current efficiencies would not enable the
units to meet the particulate emission regulations if coal is
fired in these boilers. Therefore, new ESP's are evaluated that
would allow the boilers to comply when they fire coal having
characteristics of Producing District 8. The ESP's are based on
collection efficiencies of 98.9 percent, which are needed to meet
the 0.10 lb/10 Btu regulation. Plate areas required for ESP's
2
on Boilers 20 and 30 are 290,250 and 323,450 ft , respectively.
Capital cost of the two new ESP's is estimated to be
$34,700,000 ($38.09/kW), including the coal conversion cost.
Annual operating costs, including bottom/fly ash trucking costs,
are offset by the fuel credit and result in a net annual credit
of $9,737,000 (3.28 mills/kWh).
Venturi scrubbers for particulate control have been evalu-
ated in conjunction with the sodium solution regenerable and
limestone scrubbing systems. Costs presented for the FGD systems
include venturi scrubbers.
ARTHUR KILL POWER PLANT 4-14
-------
4.1.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to coal
firing and complying with applicable emission limitations, the
recommended strategy is to fire coal from the eastern Kentucky
area in Boilers 20 and 30 and to install a limestone/venturi
scrubbing system on the units.
An assessment of alternative control methods for Arthur Kill
is summarized in Table 4-9. Emission rates and regulations for
the two boilers, based on the recommended strategy, are presented
in Table 4-10.
ARTHUR KILL POWER PLANT 4-15
-------
I
c
H
tr1
F
13
§
w
50
13
TABLE 4-9.
ESTIMATED COST OF EMISSION CONTROL OPTIONS AT THE
ARTHUR KILL POWER PLANT - 1978
Emission control
alternative
Combined SO./Particulate
controls
Low- sulfur coal
Limestone scrubbing0'
Sodium solution
regenerablec>d
Particulate control
c d
ESP installation '
Flue gas conditioning
Time
required
months
NA
40
40
36
NA
Capital cost3
106 S
98.07
121.64
34.70
S/kW
107.65
133.53
33.09
Annualized cost
Fuel
mills/kWh
(6.98)
(6.98)
(6.98)
O&M,
mills/kWh
6.40
3.89
1.97
Fixed
mills/kWh
6.29
7.99
1.73
Total
mills/kWh
5.71
4.90
(3.28)
106 S
16.96
14.55
(9.74)
a Includes coal conversion cost of $10,597,000.
Numbers in parentheses indicate credits.
c Systems are based on coal having 1.5% S, 12% ash, and 12,000 Btu/lb; costs pertain to Boilers 20 and 30.
Costs are
in January 1978 dollars; they are not escalated through project completion and do not
include replacement power.
NA - Not applicable.
I
I-1
CTi
-------
a
G
*
H
t1
f
o
:»
TABLE 4-10. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE ARTHUR KILL POWER PLANT
Fuel type
Boiler 20
Alternate fuel
Coalc
Boiler 30
Alternate fuel
Coal0
Sulfur dioxide
Actual
emission rate
lb/106 Btu
0.40
(2.38)
0.40
(2.38)
tons/yr"
2275
(13,538)
3698
(22,002)
Allowable
emission rate
lb/106 Btu
0.40
0.40
tons/yr"
2275
3698
Part iculate
Ac t ual
emission rate8
lb/106 Btu
0.10
(1.62)
0.10
(0.77)
tons/yr "
568
(9206)
920
(7087)
Allowa
emi ss ion
lb/106 Btu
0.10
0.10
ble
rate
tons/yr0
568
920
3 Numbers in parentheses represent emissions without additional control equipment. Particulate emissions
are based on an estimated combined mechanical/ESP collection efficiency of 81* for Boiler 20, and an ESP
efficiency of 91% for Boiler 30.
Based on emission factors and estimated annual coal usage.
c Emissions are based on a coal analysis of 1.5% S, 12% ash, and 12,000 Btu/lb.
i
M
-J
-------
4.2 ASTORIA PLANT
4.2.1 Plant Description
The Astoria plant (owned and operated by the Consolidated
Edison Company of New York) is located on the east bank of the
East River in New York City in Queens County. This area is part
of the New Jersey/New York/Connecticut Interstate Air Quality
Control Region (AQCR 043).
All five boilers at the Astoria plant are evaluated for
conversion to coal firing. Boilers 10, 20, 30, 40, and 50 were
placed in service in 1953, 1954, 1958, 1961, and 1961, respec-
tively, and are rated at maximum continuous generating capacities
of 165, 165, 354, 362, and 365 MW. Each of the five boilers
exhausts through a set of twin stacks, all 10 of which are 315
feet high. Boilers 10, 20, and 30 were manufactured by Babcock
and Wilcox, and Boilers 40 and 50 were manufactured by Combustion
Engineering.
Although the boilers were originally designed as coal
firing units, they have not fired coal since 1971. The boilers
currently fire oil and natural gas. Boilers 10, 20, 40, and 50
are equipped with mechanical collectors and electrostatic precip-
itators (ESP's); Boiler 30 is equipped with an ESP only.
Additional unit design and operating data are presented in
Table 4-11. A site plan of the plant is shown in Figure 4-4.
4.2.2 Fuel Supply and Characteristics
In 1975, the Astoria plant fired 1504 million ft of gas and
8.5 million bbl of oil. The fuels were purchased from a central
tank farm. The latest available fuel analyses and costs are
presented in Tables 4-12 and 4-13, respectively.
ASTORIA POWER PLANT 4-18
-------
TABLE 4-11. DESIGN AND OPERATING DATA FOR THE ASTORIA POWER PLANT
t-3
o
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input,0 10 Btu/h
Stack height, ft above grade
Flue gas rate maximum, acfm
Flue gas temperature, °F
Emission controls
Coal firing
10
165
8007
56.5
1A and IB
B&W
1953
64
1536
315
710,000
300
Mech.
coll. /ESP
20
165
5885
33.8
2A and 2B
B&W
1954
64
1536
315
710,000
300
Mech.
coll. /ESP
30
354
4409
29.4
3A and 3B
B&W
1958
130.4
3130
315
1,400,000
300
ESP
40
362
5513
38.0
4A and 4B
C-E
1961
134.2
3221
315
1,400,000
300
Mech.
coll. /ESP
50
365
7677
55.8
5A and 5B
C-E
1961
134.2
3221
315
1,400,000
300
Mech.
coll. /ESP
Information from Power Plant Survey Form (Appendix B).
B&W - Babcock & Wilcox; C-E - Combustion Engineering.
Based on coal heating value of 12,000 Btu/lb.
-------
i
n
FORMER
GAS TANKS
P
GATE
HOUSE
OO OO OO CO OO
10 20 30 40 50
DUCTING
TRANSFORMERS
00
60
PARKING AREA
STORAGE AREA
OIL TANK
O
O
O
TANKS
O
O
I
NJ
O
Figure 4-4. Site plan of the Astoria power plant.
-------
TABLE 4-12. ANALYSES OF FUEL USED AT THE ASTORIA POWER PLANT
Analysis
Heating Value
Sulfur
Fuel oila
142,788 Btu/gal
0.28%
Natural gas
1,025 Btu/ftJ
Information from Power Plant Survey Form (Appendix B).
TABLE 4-13. COSTS OF FUEL AT THE ASTORIA POWER PLANT
Fuel cost,a $/106 Btu
Type of purchase
Contract
Fuel oil
2.128
Natural gas
1.367
a Information from Electrical Week magazine, May 1, 1978.
4.2.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 043
as Priority I with respect to emissions of particulates and
sulfur oxides. Part 227.3(C) of the New York Regulations limits
particulate emissions from oil or coal firing in Boilers 10
through 50 to 0.10 lb/10 Btu heat input. The regulations under
Part 225, Table I, limit the sulfur content in residual oil to
0.30 percent, and SO? emissions from coal firing to 0.40 lb/10
Btu. Table 4-14 summarizes emission rates and applicable regula-
tions pertaining to oil firing at the Astoria plant.
Air Quality Monitoring Data —
Ambient particulate and S02 monitoring data for June 1973
through July 1974 were collected at 12 stations in the Queens
area. These data were used to characterize the ambient air
quality in the vicinity of the Astoria power plant.
The City of New York, Department of Air Resources, Bureau of
Technical Services. Fiscal Report, July 1, 1973 - June 30, 1974
ASTORIA POWER PLANT
4-21
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TABLE 4-14.
EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT FUEL
USAGE AT THE ASTORIA POWER PLANT
Fuel type
BOILER 10
Current fuel
Oil
Gas
BOILER 20
Current fuel
Oil
Gas
BOILER 30
Current fuel
Oil
Gas
BOILER 40
Current fuel
Oil
Gas
BOILER 50
Current fuel
Oil
Gas
Sulfur dioxide
Actual a
emission rate
lb/106 Btu
0.31
0.0006
0.31
0.0006
0.31
0.0006
0.31
0.0006
0.31
0.0006
tons/yr
1,154
<1
777
<].
1,366
<1
1,939
<1
2,614
<1
Allowable
emission rates
lb/106 Btuc
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
tons/yr
1,228
94
827
79
1,454
50
2,064
17
2,783
11
Particulate
Actual a
emission rate
lb/106 Btu
0.06
0.015
0.06
0.015
0.06
0.015
0.06
0.015
0.06
0.015
tons/yr
210
4
141
4
249
2
353
<1
476
•a
Allowable
emission rates
lb/106 Btu
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
tons/yr
350
27
236
27
414
13
588
7
793
4
Based on AP-42 emission factors and an oil analysis of 0.28% S and 142,788 Btu/gal. The heating value used for gas is
1000 Btu/ft3.
Based on 1975 fuel consumption.
Based on AP-42 emission factors and an oil analysis of 0.3% S (142,788 Btu/gal).
I
10
to
-------
Measurements indicate that the annual geometric mean stan-
dard for particulates was violated at 10 stations. Five of the
stations recorded values that violated the Federal primary stan-
dard. The Federal secondary standard was violated at all 10
stations, and the State primary standard was violated at 9 of the
stations. The maximum annual geometric mean concentration of 120
yg/m was recorded at the Bowery Bay station.
The 24-hour average particulate standard was also violated
at 10 stations. Four of the stations recorded values that vio-
lated Federal and State primary standards. The Federal secondary
standard was violated at six of the stations. (There is no State
secondary standard.) The maximum 24-hour concentration of 493
yg/m was recorded at the Queens College monitor.
No Federal or State S0? standards were violated at any of
the 12 monitoring stations during the July 1973 through June 1974
period. The maximum recorded annual average and 24-hour average
values were 75 ug/m and 339 yg/m , respectively; they were
measured at the Tallman Island and Bowery Bay monitors.
Figures 4-5 and 4-6 show the 12 monitoring stations and the
maximum values recorded at each station during the 1-year period.
Table 4-15 summarizes the Federal and State ambient air quality
standards and maximum concentrations recorded near the Astoria
plant.
4.2.4 Plant Programs for Complying with Emission Regulations
When the Astoria plant fires oil and natural gas, it is in
compliance with the New York particulate and SO_ emission regu-
lations. The plant has formulated no plans for compliance in the
event it is ordered to convert to coal firing.
ASTORIA POWER PLANT 4-23
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NEW JERSEY
HANUAL STATION
TELEMETRY STATION
Figure 4-5. Particulate monitoring data
for the Astoria power plant.
Upper number: annual geometric mean, yg/m
Lower number: maximum 24-hour average, yg/m
ASTORIA POWER PLANT
4-24
-------
NEW JERSEY
MANUAL STATION
TELEMETRY STATION
0.017
0.06
Figure 4-6. Sulfur dioxide monitoring data
for the Astoria power plant.
Upper number:
Lower number:
ASTORIA POWER PLANT
annual average, ppm
maximum 24-hour average, ppm
4-25
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TABLE 4-15. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
WITH THE MAXIMUM VALUES RECORDED NEAR THE ASTORIA POWER PLANT
(Concentration in yg/m )
S02
Annual average
Maximum 24-hour
average
Particulate
Annual geometric
mean
Maximum 24-hour
average
Ambient Air Quality Standards
Federal
Primary
80
365
75
260
Secondary
60
150
State
Primary
80
365
65
250
Secondary
Maximum
recorded
values
75
339
120
493
I
to
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4.2.5 Analysis of Coal Conversion Potential
2
Coal Availability —
Coal is available from central Pennsylvania (Producing
District 1) and eastern Kentucky (Producing District 8). The
mines in these areas currently have a surplus of coal; however,
if coal demand warrants the need for the development of new
mines, a minimum of 2 years would be required to provide initial
supplies.
Table 4-16 shows the characteristics of coal available to
the Astoria plant.
TABLE 4-16. ANALYSES OF COAL AVAILABLE
TO THE ASTORIA POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Central
Pennsylvania
12,000-12,500
2-2.5
9-15
Eastern
Kentucky
12,000-12,500
1-1.5
6-12
When the Astoria plant was fired by coal, barges were used
to transport coal shipments from piers in the New York Harbor
area. Coal produced in central Pennsylvania would be loaded onto
rail lines of the Consolidated Rail Corporation (ConRail) and
then transported to the ConRail coal pier at Reading, New Jersey,
for delivery to the New York Harbor area. Coal produced in the
eastern Kentucky area would be loaded onto the Chessie System,
and then transferred to ConRail for rail-to-barge transfer at the
Port Reading coal pier.
Both rail carriers have indicated that coal could be de-
livered to the Port Reading pier without any major transportation
Foster Associates, Inc. Present and Prospective Coal Supply to
the Astoria Plant - Consolidated Edison Company of New York,
Inc. September 9, 1976.
ASTORIA POWER PLANT
4-27
-------
problems. Barge shipments, however, could present some diffi-
culties because of the questionable availability of barges. Most
barge companies in the area have either sold or scrapped their
barges because of the recent decline in coal traffic. If market
conditions warrant the need for new barges, construction and
delivery would require 9 to 18 months.
Cost estimates of coal delivered to Astoria are shown in
Table 4-17. The f.o.b. mine prices are representative of current
contract purchases. Rail transportation costs include 7000-ton
volume tariffs (ConRail). Barge rate estimates were determined
by discussions with marine transportation companies; actual
negotiated rates may vary.
TABLE 4-17. ESTIMATED DELIVERED COAL COSTS FOR
THE ASTORIA POWER PLANT
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Rail :
Barge:
Total cost, $/ton
Total cost, $/10 Btu
1978 total cost, $/106 Btu
Central
Pennsylvania
19.00
6.91
1.10
27.01
1.080a
1.190a'C
Eastern
Kentucky
18.25
10.68
1.10
30.03
1.251b
1.379b'C
Based on a coal with a heating value of 12,500 Btu/lb.
Based on a coal with a heating value of 12,000 Btu/lb.
Foster Associates values escalated to 1978 dollars.
ASTORIA POWER PLANT
4-28
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Technical Factors Affecting Fuel Conversion—
Converting Astoria's five boilers back to coal firing would
necessitate modifications of the coal and ash handling systems
(such as overhauling the pulverizer, raw coal, and bottom/fly ash
systems). Burner equipment would also have to be modified and
overhauled. The plant would need a new wastewater treatment
system. The cost of restoring and/or replacing the boiler equip-
ment is estimated to be $15,546,000 (January 1978 dollars), based
on Consolidated Edison's letter to the Federal Energy Administra-
tion (FEA). Coal conversion data are presented in Table 4-18.
4.2.6 Analysis of Methods for Controlling SO,, Emissions
Low-sulfur Coal—
Coal having an analysis of about 0.25 percent sulfur and
12,000 Btu/lb would be required to meet New York's S02 emissions
regulation of 0.40 lb/10 Btu. Coal of this analysis is not
available to the Astoria plant.
Flue Gas Desulfurization (FGD)—
A sodium solution regenerable and a limestone scrubbing
system are evaluated for SO- emissions control at the Astoria
plant. The evaluations are based on coal having characteristics
representative of Producing District 8. The systems would have
to remove approximately 84 percent of the SO- emissions to meet
the 0.40 lb/10 Btu S02 regulation.
The capital cost estimate for retrofitting Boilers 10 through
50 with a sodium solution regenerable system is $224,464,000
($159.08/kW), including the coal conversion cost of $15,546,000.
The estimated annual operating cost is $24,829,000 (4.77 mills/
kWh), including a fuel credit (in switching from oil/gas firing
to coal firing). The capital cost estimate for retrofitting the
five boilers with a limestone scrubbing system is $179,485,000
($127.20/kW), including the coal conversion cost. The estimated
annual operating cost is $27,899,000 (5.36 mills/kWh), including
bottom/fly ash and sludge trucking costs and the fuel credit.
ASTORIA POWER PLANT 4-29
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en
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TABLE 4-18. COAL CONVERSION DATA FOR THE ASTORIA POWER PLANT
Boiler
No.
10
20
30
40
50
Total
Capacity
factor
(1975),
%
56.5
33.8
29.4
38.0
55.8
Fuel consumption3
Type
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Quantity /yr
1,250,000 bbl
559,300 x .103 ft3
841,900 bbl
479,700 x 103 ft3
1,479,600 bbl
304,300 x 103 ft3
2,100,400 bbl
87,300 x 103 ft3
2,831,700 bbl
73,300 x 103 ft3
Coal conversion data
Conv. cost,
$
15,546,000
Coal usage,
tons/yr
358,000
208,000
362,000
502,000
697,000
2,127,000
I
LJ
O
1975 consumption figures.
Estimated tonnage required for conversion to total coal firing, based
on coal heat rates.
-------
Costs for the sodium solution regenerable and limestone
scrubbing systems represent January 1978 dollars and are not
escalated through project completion.
4.2.7 Analysis of Methods for Controlling Particulate Emissions
Boilers 10, 20, 40, and 50 are equipped with both mechanical
collectors and ESP's; Boiler 30 is equipped with an ESP only.
The ESP's on Boilers 10 and 20 were manufactured by Western
Precipitation Division; each has a design efficiency of 97 per-
cent (which includes the contribution of the mechanical collec-
tors) . The ESP's on Boilers 30, 40, and 50 were manufactured by
Research Cottrell; each has a design efficiency of 99 percent
(which includes the contribution of the mechanical collectors on
Boilers 40 and 50). Realistic efficiency estimates for the ESP's
are based on plate areas, amount of air flow treated, sulfur
content of the coal, boiler age, and deterioration; these esti-
mates are calculated to be 56 percent on Boilers 10 and 20, 77
percent on Boiler 30, and 79 percent on Boilers 40 and 50. These
efficiencies would not allow compliance with the particulate
emission limit if coal were fired at Astoria. Therefore, new
ESP's are evaluated that would allow the boilers to operate in
compliance while firing coal characteristic of Producing District
8. The ESP's are based on collection efficiencies of 98.9 per-
cent that are needed to meet the 0.10 lb/10 Btu regulation.
Plate areas required for each new ESP on Boilers 10 and 20 are
2
estimated to be 146,250 ft ; and plate areas for Boilers 30, 40,
2
and 50 are estimated to be 290,250 ft each.
Estimated capital cost of installing new ESP's on Astoria's
five boilers, including the coal conversion cost, is $57,985,000
($41.09/kW). The annual operating cost, including bottom/fly ash
trucking costs, is offset by the fuel credit resulting in a net
annual credit of $23,611,000 (4.54 mills/kWh).
Costs of venturi scrubbers (to be used in conjunction with
the FGD systems) for particulate emission control are included in
the FGD cost evaluations.
ASTORIA POWER PLANT 4-31
-------
4.2.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the Astoria plant to
coal firing, the recommended strategy is to fire coal from the
eastern Kentucky area in Boilers 10 through 50 and to install a
limestone/venturi scrubbing system on the units to comply with
applicable SO2 and particulate emission regulations.
An assessment of alternative control methods for Astoria is
summarized in Table 4-19. Emission rates and regulations for the
five boilers, based on the recommended strategy, are presented in
Table 4-20.
ASTORIA POWER PLANT 4-32
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5
a
TABLE 4-19. ESTIMATED COSTS OF EMISSION CONTROL OPTIONS
AT THE ASTORIA POWER PLANT - 1978
Emission control
al terna t i ve
Combined SO./particulate
control
Low-sulfur coal
Limestone scrubbing
Sodium solution
regenerablec
Particulate control
ESP installation0
Flue gas conditioning
Time
required
months
NA
40
40
36
NA
Capital cost3
S 1Q6
179.49
224.46
57.99
S/kW
127.20
159.08
41.09
Annual! zed cost
Fuel,
mills/kWh
(7.73)
(7.73)
(7.73)
O&M,
mills/kWh
6.52
4.13
1.49
Fixed,
mills/kWh
6.57
8.37
1.70
Total
mills/kWh
5.36
4.77
(4.54)
S 106
27.90
24.83
(23.61)
a Includes coal conversion cost of $15,546,000.
Numbers in parentheses indicate credits.
c Systems are based on coal having 1.5% S, 12% ash, and 12,000 Btu/lb; costs pertain to Boilers 10 through
50. (ESP evaluation is based on noncomplying sulfur coal.)
NA - Not applicable.
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13
TABLE 4-20. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE ASTORIA POWER PLANT
Fuel type
BOILER 10
Alternate fuel
CoalC
BOILER 20
Alternate fuel
Coalc
BOILER 30
Alternate fuel
Coalc
BOILER 40
Alternate fuel
Coalc
BOILER 50
Alternate fuel
Coalc
Sulfur dioxide
Estimated
emission rate3
lb/106 Btu
0.40
(2.38)
0.40
(2.38)
0.40
(2.38)
0.40
(2.38)
0.40
(2.38)
tons/yr
1,715
(10,203)
996
(5,928)
1,734
(10,317)
2,405
(14,307)
3,339
(19,865)
Allowable
emission rate
lb/106 Btu
0.40
0.40
0.40
0. 40
0.40
tons/yr
1,715
996
1,734
2,405
3,339
Particulate
Actual
emission rate a
lb/106 Btu
0.10
(3.74)
0.10
(3.74)
0.10
(1.96)
0.10
(1.79)
0.10
(1.79)
tons/yr
430
(16,067)
250
(9,335)
434
(8,514)
602
(10,783)
836
(14,972)
Allowable
emission rate
lb/106 Btu
0.10
0.10
0.10
0.10
0.10
tons/yr
430
250
434
602
836
a Numbers in parentheses represent emissions without additional control equipment; particulate emissions are based on
estimated mechanical collector/ESP combined efficiencies as discussed in Section 4.2.7.
b Based on emission factors and estimated annual coal usage.
c Emissions are based on a coal analysis of 1.5% S, 121 ash, and 12,000 Btu/lb.
I
U)
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4.3 E. F. BARRETT PLANT
4.3.1 Plant Description
The Barrett power plant (owned and operated by Long Island
Lighting Company) is located in Island Park, Nassau County, New
York, in a residential area of Long Island. Simonsons Channel
borders the plant on the northwest, and Barnums Channel runs
through the center of the power plant property. This area is
part of the New Jersey/New York/Connecticut Interstate Air Qual-
ity Control Region (AQCR 043).
The Barrett plant consists of two tangentially fired boil-
ers, but only Boiler 10 is evaluated for conversion to coal
firing. Each boiler is coupled to its own turbine generator, and
each has a rated generating capacity of 175 MW. Both boilers
were manufactured by Combustion Engineering, Inc. Boiler 10,
which began operation in 1956, can fire coal, oil, or natural
gas; Boiler 20, which began operation in 1963, can fire only
natural gas and oil. Boiler 10 could maintain a capacity of only
150 MW if converted to 100 percent coal firing. Both boilers are
equipped with mechanical collectors. In addition, Boiler 10 is
equipped with an electrostatic precipitator (ESP).
Additional unit design and operating data are presented in
Table 4-21. A site plan of the plant is shown in Figure 4-7.
4.3.2 Fuel Supply and Characteristics
The Barrett plant has been firing oil and natural gas since
1969, when it discontinued firing coal. In 1975 Boiler 10 fired
1.43 million bbl of No. 6 fuel oil and 669 million ft3 of natural
gas. The oil was obtained from the New England Petroleum Company
and the Anschutz Petroleum Marketing Corporation. The latest
available fuel analyses and costs are presented in Tables 4-22
and 4-23.
BARRETT POWER PLANT 4-35
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CD
>
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M
tr1
i-3
TABLE 4-21. DESIGN AND OPERATING DATA FOR THE E.F. BARRETT POWER PLANT
I
Ul
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input, 10 Btu/h
Stack height, ft above grade
Flue gas rate maximum, acfm
Flue gas temperature, °F
Emission controls
Coal firing
ioa
175°
7,496
61
1
C-E
1956
NA
l,47ie
250
518,000
281
Mechanical
20b
175
8,205
67
2
C-E
1963
0
l,129f
350
NA
NA
Mechanical
collector
Information from Power Plant Survey Form (Appendix C) .
Information from Federal Power Commission (FPC) Form 67 (1975).
Boiler 10 is derated to 150 MW when firing only coal.
Combustion Engineering, Inc.
Based on coal heating value of 13,300 Btu/lb and a gas heating value
of 1026 Btu/ft3.
Based on oil heating value of 142,696 Btu/gal .
N." -
-------
HOG ISLAND CHANNa
Figure 4-7. Site plan of the Barrett power plant.
BARRETT POWER PLANT
4-37
-------
TABLE 4-22. ANALYSES OF FUEL BURNED AT THE BARRETT POWER PLANT
Analysis
Heating Value
Sulfur
No. 6 fuel oil
142,696 Btu/gal
0.37%
Natural gas
1,026 Btu/ft
a Information from Power Plant Survey Form (Appendix C)
TABLE 4-23. COSTS OF FUEL AT THE BARRETT POWER PLANT
Fuel cost,3 $/106 Btu
Type of purchase
Contract
No. 6 fuel oil
2.250
Natural gas
1.500
Information from Electrical Week magazine, December 1977.
4.3.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 043
as Priority I with respect to emissions of particulates and sul-
fur oxides. Current New York regulations limit particulate
emissions to 0.10 lb/10 Btu for both oil firing [Part. 227.3
(c)(l)] and coal firing [Part. 227.3(a), Table 1]. The regula-
tions limit sulfur dioxide (SO.,) emissions to 0.41 lb/10 Btu
fi
heat input for oil firing and 0.40 lb/10 Btu heat input for coal
firing (Part. 225, Table 1). In addition, the sulfur content of
fuel oil is limited to 0.37 percent by weight.
Table 4-24 summarizes emission rates and applicable regula-
tions for the Barrett power plant.
Air Quality Monitoring Data—
In 1975 ambient SO2 monitoring data were collected at three
stations. (See Figure 4-8.)
BARRETT POWER PLANT
4-38
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w
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50
TABLE 4-24. EMISSION RATES AND APPLICABLE REGULATIONS FOR
CURRENT FUEL USAGE AT THE E.F. BARRETT POWER PLANT
Fuel type
BOILER 10
Current fuel
Oil
Gas
Sulfur dioxide
Estimated
emission ratea
lb/106 Btu
0.407
0.0006
tons/yr
1,740
0.21
Allowable
emission rates
lb/106 Btu
0.41
0.41
tons/yr
1 ,757
140.7
Particulate
Actual
emission rate3
lb/106 Btu
0.06
0.015
tons/yr
240
5.0
Allowable
emission rates
lb/106 Btu
0.1
0.1
tons/yr
428
34.32
a Based on the following fuel analysis: Natural gas with heating value of 1,026 Btu/ft3 and No. 6 oil with 0.374 S and
142,696 Btu/gal.
I
U)
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UNIONDALE
ELMONT •
MALVERNE
VALLEY STREAM
HEWLETT
ROCKVILLE
ENTER
LAWRENCE
& E.F. BARRETT POWER STATION
• LILCO S02 MONITORING STATIONS
* LILCO METEOROLOGICAL TOWER
3
i
SCALED IN KILOMETERS
Figure 4-8. Sulfur dioxide monitoring sites for
the E.F. Barrett power plant.
BARRETT POWER PLANT
4-40
-------
The maximum annual arithmetic mean S09 concentration measured
3 ^
at the Lido Beach monitor was 14 yg/m . The maximum 24-hour and
maximum 1-hour SCU concentrations were 65 yg/m at Baldwin Harbor
o *
and 150 yg/m at Lido Beach, respectively. These values are well
below Federal and State ambient S02 standard levels.
No ambient particulate monitoring data are currently avail-
able.
Table 4-25 summarizes the Federal and State ambient air
quality standards and the maximum recorded ambient air values.
4.3.4 Plant Programs for Complying with Emission Regulations
The Barrett plant presently complies with New York's S02 and
particulate emission regulations by firing No. 6 fuel oil and
natural gas. However, in the event that Boiler 10 is ordered to
convert totally to coal firing, both regulations would be vio-
lated.
Long Island Light has indicated the steps that would be
required to comply with the New York emission regulations in the
event that Barrett is ordered to convert Boiler 10 to coal fir-
ing. The Company has proposed to meet the particulate emission
regulation by installing a new ESP in parallel with the existing
unit to raise the total efficiency of the fly ash removal system
to 98 percent or higher. The Company proposes to comply with the
S02 emission regulations by installing an S02 removal system, if
necessary. It is estimated that the conversion of Boiler 10 from
oil to coal firing (using existing equipment) could be accom-
plished during a 2-week outage. An additional outage of 10 weeks
would be required to install the new ESP.
4.3.5 Analysis of Coal Conversion Potential
Coal Availability —
High-sulfur coal is available from western Pennsylvania and
northern West Virginia (Producing Districts 2 and 3). Both
Foster Associates, Inc. Present and Prospective Coal Supply to
the Barrett, Far Rockaway, and Port Jefferson Plants - Long
Island Lighting Company. September 9, 1976.
BARRETT POWER PLANT 4-41
-------
00
TABLE 4-25. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
'WITH THE .MAXIMUM VALUES RECORDED NEAR THE E.F. BARRETT POWER PLAT.JT
(Concentration in yg/m3)
13
O
32
M
13
f
so2
Annual average
Maximum 2 4 -hour
average
Maximum 1-hour
average
Particulate
Annual geometric
mean
Maximum 2 4 -hour
average
Ambient Air Quality Standards
Federal
Primary
80
365
75
260
Secondary
60
150
State
Primary
80
260a
1300b
65
250
Secondary
Maximum
recorded
values
14
65
150
a State standards say that not more than 1% of the 24-hour average concentration
shall exceed 20 yg/m3.
b 99% of the 1-hour average concentrations shall not exceed 650 yg/m, and no
1-hour average concentration shall exceed 1300 yg/m3.
-------
districts currently have a surplus of coal; however, the current
surplus is dependent upon market conditions. If new mining
capacity is required, it will take 2 to 5 years before initial
coal supplies can be available.
Low-sulfur coal is available from southern West Virginia and
eastern Kentucky (Producing Districts 7 and 8), which also cur-
rently have a surplus of coal.
Table 4-26 shows characteristics of coal available to the
Barrett plant.
TABLE 4-26. ANALYSES OF COAL AVAILABLE TO
THE BARRETT POWER PLANT
Western Pennsylvania and
northern West Virginia
Eastern Kentucky and
southern West Virginia
Heating value,
Btu/lb
Sulfur, %
Ash, %
12,000 - 12,500
2.0 - 3.0
9-15
12,000 - 12,500
1.0 - 1.5
6-12
The Long Island Railroad would transport coal to the Barrett
plant. Coal produced in the western Pennsylvania and northern
West Virginia producing districts would be loaded onto the Con-
solidated Rail Corporation (ConRail) rail lines and then trans-
ferred to the Long Island Railroad at New York City. Coal sup-
plies from the southern West Virginia and eastern Kentucky
producing districts would be loaded onto the Chessie System and
then transferred first to ConRail at Philadelphia and then to the
Long Island Railroad at New York City.
BARRETT POWER PLANT
4-43
-------
The spur leading from the Long Island Railroad main line
would have to be modified and extended before large-volume hopper
cars could move into the plant. Deliveries via existing facili-
ties would interfere with automobile traffic on a major traffic
artery near the plant. The town and fire department of Hemstead
will not allow the substantial blockage of this road that would
be associated with coal deliveries. In addition, scheduling
problems may occur on the ConRail rail lines since portions of
the former Penn Central main line and branch lines remain under
orders to limit train speeds to 30 mph. Funds are now available
for upgrading deteriorated rail lines, and repairs are underway.
Table 4-27 shows delivered costs of coal produced in western
Pennsylvania and eastern Kentucky.
TABLE 4-27. ESTIMATED DELIVERED COAL COSTS FOR THE
BARRETT POWER PLANT
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/106 Btu
Western
Pennsylvania
18.50
11.00
29.50
1.190a
1.31la'C
Eastern
Kentucky
18.50
13.64
32.14
1.339b
1.476b'C
Based on a coal with a heating value of 12,400 Btu/lb.
Based on a coal with a heating value of 12,000 Btu/lb.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Fuel Conversion--
Boiler 10 currently fires oil and natural gas. An order to
fire coal would require reconditioning of the boilers, modifica-
tion of coal and ash handling systems, and replacement or modifi-
cation of electrical items, instruments, and controls. A rotary
BARRETT POWER PLANT
4-44
-------
railroad car dumper would be required to replace the existing car
shaker (which cannot be used because it produces a noise level
above 125 decibels in a residential area within 1000 feet of the
plant).
Based on information obtained from Long Island Light, the
estimated capital cost for coal conversion is $12,203,000, which
includes wastewater treatment and ash disposal. (This total does
not include the cost of ash handling, which is attributable to
new control equipment.) Coal conversion data are presented in
Table 4-28.
4.3.6 Analysis of Methods for Controlling S02 Emissions
Low-sulfur Coal—
Coal having a sulfur content that would comply with the New
York SO- emission regulations cannot be obtained for this plant.
Flue Gas Desulfurization (FGD)—
A sodium solution regenerable and a limestone scrubbing
system are evaluated for S02 emission control at the Barrett
plant. The systems are based on coal characteristics representa-
tive of Producing District 8 and would require approximately 83
percent removal capability to meet the 0.40 lb/10 Btu S02
regulation.
The estimated capital cost of retrofitting Boiler 10 with a
sodium solution regenerable system is $31,685,000 ($211.23/kW),
which includes the coal conversion cost of $12,203,000. An-
nualized costs are offset by the fuel credit, resulting in a
credit of $1,712,000 (2.17 mills/kWh). The estimated capital
cost of retrofitting Boiler 10 with a limestone scrubbing system
is $29,399,000 ($195.99/kW), which includes the coal conversion
cost. The annualized credit is estimated to be $2,162,000 (2.74
mills/kWh). Costs of both FGD systems also include venturi
scrubbers to reduce particulate levels to allowable rates.
BARRETT POWER PLANT -4-45
-------
TABLE 4-28. COAL CONVERSION DATA FOR THE BARRETT POWER PLANT
O
s
w
JO
H3
f
>
z
Boiler
No.
10
Capacity
factor
(1975) ,
%
61a
Fuel consumption*3
Type
Oil
Gas
Quantity/yr
1.43 x 106 bbl
669 x 106 ft3
Coal conversion data
c
Conv. cost,
$
12,203,000
12,203,000
Coal usage.,
tons/yr
322,000
322,000
3 Boiler 10 is derated to 150 MW when firing only coal.
Based on data in 1975 FPC Form 67.
c Coal conversion cost is escalated to January 1978 dollars and adjusted to
exclude equipment included in new control equipment cost analysis.
Coal required for total conversion to 100% coal firing.
I
£*
cn
-------
4.3.7 Analysis of Methods for Controlling Particulate Emissions
The multiple-cyclone collector and ESP on Boiler 10 were
manufactured by Buell Engineering Company, Inc.; the units have a
total design efficiency of 97.9 percent. These units cannot
bring the plant into compliance with the New York particulate
regulation of 0.10 lb/10 Btu when firing coal; therefore a new
ESP would be required. The evaluation of the ESP is based on a
collection efficiency of 98.82 percent while firing coal char-
acteristic of Producing Districts 7 and 8. Plate area required
for the ESP is estimated to be 106,313 ft2.
Capital cost of installing a new ESP on Boiler 10 is
$16,059,000 ($107.06/kW), including the coal conversion cost.
Annualized costs are offset by the fuel credit, resulting in a
credit of $7,435,000 (9.43 mills/kWh).
4.3.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to coal
firing, the recommended strategy is to fire coal from the eastern
Kentucky area and to install a limestone/venturi scrubbing system
on Boiler 10 to comply with applicable SO- and particulate emis-
sion regulations.
Assessment of the alternative control methods is summarized
in Table 4-29. Emission rates and regulations based on the
recommended strategy are presented in Table 4-30.
BARRETT POWER PLANT 4-47
-------
00
w
TABLE 4-29.
ESTIMATED COST OF EMISSION CONTROL OPTIONS AT THE
BARRETT POWER PLANT - 1978
i
M
13
IT1
Emission control
alternative
Combined SO2/particulate
controlsc
Limestone scrubbing
Sodium solution
regenerable
Particulate control
Electrostatic precip-
itator installation
Flue gas conditioning
Time
required
months
36
36
36
NA
Capital cost3
S 106 $/kW
29.40 195.99
31.69 211.23
16.06 107.06
Annualized cost?'b
Fuel,
mills/kWh
(10.83)
(10.83)
(10.83)
OiM,
mills/kWh
3.42
3.37
0.35
Fixed,
mills/kwh
4.67
5.29
1.05
Total
mills/kWh
(2.74)
(2.17)
(9.43)
S 106
(2.16)
(1.71)
(7.44)
a Costs represent January 1978 dollars; they are not escalated through project completion and do not include
replacement power.
Numbers in parentheses are credits.
c All control equipment costs for boiler 10 are based on the following coal analysis: 1.5« sulfur, 12% ash, and
12,000 Btu/lb.
NA - Not applicable.
.fc.
I
00
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CO
i
w
S3
13
TABLE 4-30. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE BARRETT POWER PLANT
Fuel type
BOILER 10
Alternate fuelb
Coal
Sulfur dioxide
Estimated
emission rate3
lb/106 Btu
0.40
<2.4)d
tons/yr
1,546C
(9,183)c>a
Allowable
emission rates
lb/106 Btu
0.40
tons/yr
1,546
Particulate
Actual
emission rate3
lb/106 Btu
°-1 H
(0.2)d
tons/yr
387C .
(744)c'd
Allowable
emission rates
lb/106 Btu
0.1
tons/yr
387
a Based on the following coal analysis: 1.5* S, 6-12* ash, and 12,000 Btu/lb.
Based on 100% coal firing and the installation of a limestone/venturi flue gas desulfurization system.
Annual emissions are based on 150 MW output and a capacity factor estimated by LILCO to be 60% when firing coal.
Numbers in parentheses indicate potential emissions resulting from conversion to coal firing without the installation
of additional control equipment.
I
Ji
10
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4.4 BERGEN PLANT
4.4.1 Plant Description
The Bergen power plant, owned and operated by Public Service
Electric and Gas Company (PSE&G), is located on the east bank of
the Hackensack River and on the west bank of the Overpeck Creek
in Ridgefield, Bergen County, New Jersey. This area is part of
the New Jersey-New York-Connecticut Air Quality Control Region
(AQCR 043).
The Bergen plant has two pulverized-coal, front-firing, wet-
bottom boilers built by Foster Wheeler. Boiler 1 was installed
in 1959 and Boiler 2, in 1960. Boiler 1 is rated at 287 MW and
Boiler 2 at 283 MW, yielding a total maximum continuous generat-
ing capacity of 570 MW. The boilers were designed to fire coal,
but are capable of firing residual oil and natural gas without
derating, and have been doing so since 1971. Each boiler ex-
hausts through an individual 306-ft stack, and each is equipped
with a Research-Cottrell combination mechanical collector and
electrostatic precipitator (ESP) with a design efficiency of 98
percent.
Table 4-31 presents additional boiler design and operating
data on these boilers, which are evaluated for reconversion to
coal firing. Figure 4-9 shows a site plan of the plant.
4.4.2 Fuel Supply and Characteristics
The Bergen plant has burned residual oil and natural gas
since 1971. In 1975, Boilers 1 and 2 fired approximately 2,576,100
barrels of residual oil and 2042 million cubic feet of natural
gas. Residual oil is obtained, under contract, from Amerada
Hess; natural gas is obtained from various suppliers on an inter-
ruptible basis. Tables 4-32 and 4-33 present the latest avail-
able fuel analyses and costs.
BERGEN POWER PLANT 4-50
-------
TABLE 4-31. DESIGN AND OPERATING DATA ON THE BERGEN POWER PLANT
DO
M
JO
O
W
2!
13
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average Capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat inputc, 106 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
Coal
1
287
5838
48.1
1
F-W
1959
121
2712
306
1,000,000
269
ESP and mechanica!
collector
firing
283
3092
23.8
2
F-W
1960
121
2674
306
1,000,000
269
ESP and mechanical
collector
a Information from Power Plant Survey Form (Appendix D)
b FW - Foster Wheeler Corporation.
c Based on coal heat rate of 9450 Btu/kWh.
I
Ul
-------
N
BERGEN
GENERATING
STATION
THAWING
UJ
Figure 4-9. Site plan of the Bergen power plant.
'BERGEN POWER PLANT
4-52
-------
TABLE 4-32. ANALYSES OF FUEL FIRED AT THE BERGEN POWER PLANT
Analysis
Heating value
Sulfur
Fuel oil
142,238 Btu/gal
0.3%
Natural gas
1029 Btu/ft3
Information from Power Plant Survey Form (Appendix D)
TABLE 4-33. FUEL COSTS AT THE BERGEN POWER PLANT
Type of purchase
Contract
Interruptible
Fuel cost,3 $/106 Btu
Residual oil
2.243
Natural gas
2.052b
Information from Electrical Week magazine, July 24, 1978.
Cost based on price of natural gas at the Hudson power
plant.
4.4.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 043
as Priority I with respect to emissions of particulates and
sulfur oxides.
New Jersey Administrative Code (N.J.A.C.) Regulation 7:27-4.2
limits particulate emissions to 0.10 lb/10 Btu heat input per
stack. Because the Bergen power plant has been classified by the
State as a reconstructed existing coal source by N.J.A.C. 7:27-
10.3(a), it is limited by N.J.A.C. 7:27-10.2(d) and (e)-l to
burning coal with a sulfur content no greater than 0.2 percent
or, if a sulfur dioxide (SO-) scrubbing system is used, to 0.3
r ^
lb/10 Btu heat input. Table 4-34 summarizes emission rates and
regulations covering the Bergen power plant when burning residual
oil and natural gas.
BERGEN POWER PLANT
4-53
-------
tt)
w
»
o
w
O
s:
w
TABLE 4-34. EMISSION RATES AND APPLICABLE REGULATIONS
FOR THE BERGEN POWER PLANT WHEN FIRING CURRENT FUELS
Fuel typo
Boiler 1
Current fuel
Oil
Gas
Boiler 2
Current fuel
Oil
Gas
Sulfur dioxide
Actual
emission rate
lb/106 Btu
0. 33
0.0006
0.33
0.0006
tons/yr
1606
1
942
<1
Allowable
emission rate
lb/106 Btu
0.33
0. 3
0.33
0. 3
tons/yr
1606
275
942
41
Part iculatea
Actual
emission rate
lb/106 Btu
0.056
0.015
0.056
0.015
tons/yr
273
13
160
2
Allowable
emission rate
lb/106 Btu
0.1
0.1
0.1
0.1
tons/yr
485
92
284
14
a Emissions are based on AP-42 emission factors and the following fuel analyses: oil - 0.3 percent sulfur
and 142,238 Btu/gal; gas - 1029 Btu/ft3.
SO-, emission regulations are: oil - 0.3% sulfur and gas - 0.3 lb/10 Btu.
I
Ul
-------
Air Quality Monitoring Data—
No monitoring data on ambient particulate or ambient S02
concentrations are currently available.
4.4.4 Plant Programs for Complying with Emission Regulations
The Bergen plant is in compliance with the SG>2 and particu-
late emission regulations when firing residual oil and natural
gas. Under current conditions, the plant would exceed both SO^
and particulate emission limitations when firing coal. Officials
of PSE&G have evaluated costs of a magnesium oxide SC>2 scrubbing
system in the event Boilers 1 and 2 are reconverted to 100 per-
cent coal firing, but they have not formulated compliance plans.
4.4.5 Analysis of Coal Conversion Potential
Coal Availability —
Coal for the Bergen power plant is available from central
Pennsylvania (Producing District 1), northern West Virginia
(Producing District 3), and the eastern Kentucky/southern West
Virginia area (Producing Districts 7 and 8). Producers and sales
agents indicate that coal requirements could be met with existing
mining capacity and expanding capacity at the existing mines.
None of the sources, however, could supply coal that satisfies
the SO- regulation. The lowest-sulfur coal required in conjunc-
tion with a flue gas desulfurization (FGD) system (to meet the
stringent regulation) is produced in the southern West Virginia/
eastern Kentucky area.
Coal produced in eastern Kentucky would be loaded onto the
Chessie System (C&O-B&O) rail lines and transferred to the Con-
solidated Rail Corporation (ConRail) lines in Philadelphia.
ConRail's lines on the plant site are in serviceable condition
and can accommodate unit train shipments.
Foster Associates, Inc. Present and Prospective Coal Supply
to the Bergen Plant - Public Service Electric and Gas Company,
September 9, 1976.
BERGEN POWER PLANT 4-55
-------
Tables 4-35 and 4-36 present an average coal analysis and
estimated costs of delivered coal.
TABLE 4-35. ANALYSIS OF AVERAGE COAL AVAILABLE TO THE
BERGEN POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Eastern Kentucky
(Producing District 8)
12,000 - 12,500
1.0 - 1.5
6-12
TABLE 4-36. ESTIMATED COAL COSTS FOR THE BERGEN POWER PLANT
Price, f.o.b. mine, $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/10 Btu
1978 total cost, $/106 Btu
Eastern Kentucky
(Producing District 8)
18.25
13.41
31.66
1.454
a
a,b
a Based on a heating value of 12,000 Btu/lb.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Fuel Conversion--
Coal handling equipment, pulverizers, crushers, and ash
handling equipment are still in place, but extensive maintenance
would be required to make this equipment operational. Public
Service Electric and Gas Company officials estimate the coal con-
version cost to be $11,384,000. Additional operating and main-
tenance costs due to coal firing are estimated to be $1,491,000.
Table 4-37 presents a breakdown of coal conversion data by boiler,
BERGEN POWER PLANT
4-56
-------
Table 4-37
COAL CONVERSION DATA FOR THE BERGEN POWER PLANT
CO
W
»
en
w
z
Boiler
NO.
1
2
Total
Capcity
factor
(projected) ,
%
41
41
Fuel consumption
Type
Oil
Gas
Oil
Gas
Quantity/yr
1,623,800 bbl
1,779.1 106 ft3
952,300 bbl
262.6 106 ft3
Coal conversion data
Conv. cost,
$
11,384,000
Coal usage,
ton/yr
406,000
400,000
806,000
f
1
t-3
Information from Power Plant Survey Form (Appendix D).
Additional coal required for coal conversion; based on a capacity
factor of 41 percent, a heat rate of 9,450 Btu/kWh, and a heating
value of 12,000 Btu/lb.
Based on estimate from Public Service Electric and Gas Company
contained in July 9, 1975/ letter to FEA; costs escalated to
January 1978 dollars.
i
m
-------
4.4.6 Analysis of Methods for Controlling SO,, Emissions
Low-sulfur Coal—
No available coal can be guaranteed to meet New Jersey's 0.2
percent sulfur content limitation.
Flue Gas Desulfurization (FGD)—
This report evaluates limestone scrubbing and sodium solu-
tion regenerable systems for control of SC>2 emissions at the
Bergen plant. The evaluations are based on the 87.4 percent
removal capabilities required to meet New Jersey's standards when
firing coal with an analysis of 1.5 percent sulfur, 12 percent
ash, and 12,000 Btu/lb.
The capital cost of retrofitting the Bergen plant with a
limestone scrubbing system, including a coal conversion cost of
$11,384,000 is estimated to be $102,667,000 ($180.12/kW). Annual
operating costs, including trucking costs and additional operat-
ing and maintenance costs (allowing for a fuel credit in switch-
ing from oil/gas firing to coal firing), is estimated to be
$17,750,000 (8.67 mills/kWh).
The capital cost of installing a sodium solution regenerable
system is estimated to be $115,110,000 ($201.95/kW), including
coal conversion costs. Annual operating costs are estimated to
be $16,743,000 (8.18 mills/kWh).
4.4.7 Analysis of Methods for Controlling Particulate Emissions
Each of the boilers is equipped with a Research-Cottrell
combination mechanical collector and ESP with a design efficiency
of 98 percent on high-sulfur coal. When the boilers are firing
low-sulfur (1.5%) coal, the efficiency drops to about 94.4 per-
cent. Since efficiency must be at least 98.5 percent to comply
with the particulate emission regulation when firing coal,
Boilers 1 and 2 would not be in compliance.
BERGEN POWER PLANT 4-58
-------
One method of complying with particulate emission limita-
tions is to install add-on ESP's on each boiler to bring the
overall collection efficiency up to 98.46 percent. Required
plate areas for ESP's on Boilers 1 and 2 are 718,200 and 244,728
2
ft . The capital cost of installing add-on ESP's is estimated to
be $40,234,000 ($70.59/kW), including a coal conversion cost of
$11,384,000. Annual operating costs, including bottom and fly
ash removal and additional operating and maintenance costs, are
outweighed by a fuel credit, resulting in a net credit of $5,705,000
(2.79 mills/kWh). This emission control alternative can be used
only if the plant obtains a variance on the S02 emission regula-
tion.
Another method of complying with particulate emission limi-
tations on Boilers 1 and 2 when firing 1.5 percent sulfur coal is
to install venturi scrubbers on the boilers. Capital and annual
operating costs of venturi scrubbers are included in the FGD
costs.
4.4.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for reconverting Bergen Boilers 1
and 2 to coal firing, the recommended strategy is to fire coal
from eastern Kentucky and to install a sodium solution regen-
erable FGD system with venturi scrubbers to achieve compliance
with applicable SO2 and particulate emission regulations.
Table 4-38 presents cost assessments for optional control
systems for Boilers 1 and 2. Table 4-39 presents emission rates
and regulations based on the recommended strategy.
BERGEN POWER PLANT 4-59
-------
03
W
?0
O
W
o
50
a
t-3
TABLE 4-38. COST ASSESSMENT FOR EMISSION CONTROLS
AT THE BERGEN POWER PLANT - 1978
Emission control alternative
SCU/particulate control
Limestone scrubbing on Boilers
1 and 2d
Sodium soln. regenerable systems
on Boilers 1 and 2d
Particulate control
Add-on ESP's on Boilers 1 and 2d
Time
requi red ,
months
36
36
36
Capital cost
106 S
102.667
115.110
40.234
S/kW
180.12
201.95
70.59
Annualized cost
Fuel ,
mills/kwh
(8.15)
(8.15)
(8.15)
OSM,C
mills/kWh
7.52
5.77
2.49
Fixed,
mills/kUh
9.30
10.56
2.87
mills/kWh
3.67
8.18
(2.79)
-•'~K
106 $
17.75
16.74
(5.71)
Costs are in January 1978 dollars; have not been escalated through project completion; do not include replacement
power.
k Includes a coal conversion costs of $11,384,000.
c Costs include additional operating and maintenance costs of $1,353,000 submitted by PSEiG; escalated to January
1978 dollars.
d systems are based on a coal analysis of 1.5 percent sulfur, 12.0 percent ash, and 12.00C> Btu/lb. Coal of this sulfur
content would violate the current S0? regulation. Numbers in parentheses represent credits.
I
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00
W
?0
CD
W
z
i
w
TABLE 4-39. EMISSION RATES AND REGULATIONS IF RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY IS APPLIED AT THE BERGEN POWER PLANT
Fuel type
Boiler 1
Alternate fuel
Coal
Boiler 2
Alternate fuel
Coal
Sulfur dioxide3
Actual
emission rate
lb/106 Btu
0.3
(2.375)
0.3
(2.375)
tons/yr
1.461
(11,567)
1,441
(11.406)
Al lowable
emission rate
lb/10G Btu
0.3
0. 3
tons/yr
1,461
1,441
Particulate a
Actual
emission rate*3
lb/106 Btu
0.1
(0.36)
0.1
(0. 36)
tons/yr
487
(1,776)
480
(1,751)
Allowable
emission rate
lb/106 Btu
0.1
0.1
tons/yr
487
480
Emissions are based on AP-42 emission factors and a coal analysis of 1.5 percent sulfur, 9.0 percent ash,
and 12,000 Btu/lb. Numbers in parentheses represent potential emissions resulting from full conversion
to coal firing without the installation of additional emission control equipment. The estimated efficiency
of each existing ESP is 94.4 percent.
SO2 emission regulation for coal firing is 0.2 percent sulfur content or 0.3 lb/106 Btu if a scrubbing
system is used.
-------
4.5 BLUE VALLEY PLANT
4.5.1 Plant Description
The Blue Valley power plant (owned and operated by the City
of Independence Power and Light Department) is located in Inde-
pendence, Missouri. This area is part of the Metropolitan Kansas
City Interstate Air Quality Control Region (AQCR 094).
The three pulverized-coal-fired boilers at Blue Valley are
being evaluated for coal conversion. Boilers 1, 2, and 3 were
placed in commercial operation in 1958, 1958, and 1965, respec-
tively, and have continuous generating capacities of 24, 24, and
60 MW. All of the boilers are capable of firing coal, oil, or
natural gas; Boiler 3, however, is derated 10 percent (from 60 to
54 MW) when firing coal. Boilers 1 and 2, which exhaust through
individual 152.5-ft stacks, are each equipped with a multicyclone
mechanical collector with a design efficiency of 85 percent;
Boiler 3, which exhausts through a 250-ft stack, is equipped with
a multicyclone collector with a design efficiency of 90.3 percent,
Additional boiler design and operating data are presented in
Table 4-40. A site plan of the plant is shown in Figure 4-10.
4.5.2 Fuel Supply and Characteristics
In 1975, the Blue Valley boilers fired 130,744 tons of coal,
8,050 bbl of residual oil, and 2,941 million ft of natural gas.
On December 23, 1975, the plant converted its boilers to 100
percent coal firing after receiving a particulate emissions
variance from the State of Missouri. Since then, Blue Valley
fired some oil and natural gas whenever these fuels were avail-
able.
Coal is purchased from mines in Oklahoma; fuel oil was pur-
chased from the Reese Oil Company in Kansas City, Kansas, and
from American Oil Company in Sugar Creek, Missouri. The latest
available fuel analyses and fuel costs are presented in Tables
4-41 and 4-42.
BLUE VALLEY POWER PLANT 4~62
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TABLE 4-40. DESIGN AND OPERATING DATA FOR THE BLUE VALLEY POWER PLANT
03
s
W
F1
F
W
K
O
s
w
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975), %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input, 106 Btu/hc
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
a
Coal firing
1
24
5,164
36.1
1
C-E
1958
16.1
300
152. 5
93,000
303
Mechanical
collector
2
24
7,537
59.5
2
C-E
1958
16.1
300
152. 5
93,000
303
Mechanical
collector
3
54
7,012
53.4
3
C-E
1965
29.4
605
250
202,000
303
Mechanical
collector
Information from Power Plant Survey Form (Appendix E).
C-E - Combustion Engineering.
° Based on heat rates of 12,500, 12,500, and 11,200 Btu/kWh
for Boilers 1, 2, and 3, respectively.
I
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w
*
I
"a
LIKE
QFUtL CIL L'NLOA3IH
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TABLE 4-41. ANALYSES OF FUEL USED AT THE
BLUE VALLEY POWER PLANT
Analysis
Heating value
Sulfur
Ash
Coal3
10,907 Btu/lb
2.47%
13.5%
oiia
138,266 Btu/gal
0.12%
Natural gas
987 Btu/ft3
a Information from Power Plant Survey Form (Appendix E).
TABLE 4-42. COSTS OF FUEL AT THE BLUE VALLEY POWER PLANT
Type of Purchase
Fuel cost, $/10 Btu
Spot
Spot
Interruptible
1.088 (Coal)
2.588b (Oil)
1.052 (Natural gas)
a Information from Federal Power Commission (FPC) Form 423,
February 1976.
b Information from Electrical Week magazine, December 1977.
4.5.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 094
as Priority I with respect to particulate emissions, and Priority
III with respect to sulfur oxide emissions.
Section B(1C) of Regulation No. Ill of the Missouri regula-
tions limits particulate emissions at the Blue Valley plant to
0.24 lb/106 Btu heat input. The sulfur dioxide (S02) emission
regulation and ambient air fenceline standard under Section I of
Regulation XV limit emissions to a 1-hour average of 0.25 ppm or
greater once in any 4 days or a 24-hour average of 0.07 ppm or
greater once in any 90 days.
Table 4-43 summarizes emission rates and regulations for
coal, oil, and gas firing at the Blue Valley power plant.
BLUE VALLEY POWER PLANT
4-65
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TABLE 4-43. EMISSION RATES AND APPLICABLE REGULATIONS FOR
CURRENT FUEL USAGE AT THE BLUE VALLEY POWER PLANT
f
t4
w
i
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13
Fuel type
BOILER 1
Current fuel
Coal
Oil
Gas
BOILER 2
Current fuel
Coal
Oil
Gas
BOILER 3
Current fuel
Coal
Oil
Gas
Sulfur dioxide
Actual a
emission rate
lb/106 Btu
4. 30
0.14
0.0006
4. 30
0. 14
0.0006
4.30
0.14
0.0006
tons/yr
980
<1
<1
1425
<1
<1
3731
<1
<1
Al lowable
emission rate
lb/106 Btu
b
b
b
tons/yr
b
b
b
Particulate
Actual
emission rate
lb/106 Btu
1.58°
0.06
0.015
1.58C
0.06
0.015
1.02C
0.06
0.015
tons/yr
359C
<1
4
523C
<1
7
885C
<1
12
Al lowable
emission rate
lb/106 3tu
0.24
' 0.24
0.24
tons/yr
55
79
134
a Based on an analysis of 10 907 Btu/lb, 2.47» sulfur, and 13.5% ash for coal; 138,266 Btu/gal and 0.12* sulfur for oil:
and 987 stC/f?" for natural gas Emissions are based on AP-42 emission factors and 1975 fuel consumption.
b Ambient Air Fenceline Standard 1-hour average of 0.25 ppm or greater in any 4 days or 24-hour average of 0.07 PPm or
greater once in 90 days.
c Based on mechanical collector design efficiencies of 85%, 85%, and 90.3% for Boilers 1, 2, and 3, respectively.
I
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Air Quality Monitoring Data —
Ambient S02 monitoring data (third quarter of 1975) are
available from six stations, and ambient suspended particulate
monitoring data (first three quarters of 1975) are available from
11 stations in the Independence area.
Measurements show that State primary and Federal secondary
ambient particulate standards were exceeded at seven monitoring
sites (based on averages of three quarters in 1975). A maximum
annual geometric mean concentration of 125 pg/m was recorded at
a monitor located at 405 Missouri Avenue, Kansas City, Missouri.
Although no measured 24-hour average particulate concentrations
are available, it is likely that the State primary and Federal
secondary ambient particulate standards (based on the 24-hour
averaging time) were violated at the monitor at which the annual
maximum was recorded.
Measurements also show that no State or Federal ambient S02
standards were violated in the third quarter of 1975. The maxi-
mum measured average concentration (14 ng/m ) was registered at
the same Missouri Avenue monitor. The State and Federal ambient
air regulations and the maximum recorded values are summarized in
Table 4-44.
4.5.4 Plant Programs for Complying with Emission Regulations
Blue Valley presently is firing coal and, on an interrupt-
ible basis, natural gas and oil. The plant has a particulate
emissions variance from the State of Missouri and company offi-
cials have contracted with Burns and McDonnell to determine the
requirements necessary for compliance with the applicable particu-
late limitation. The report Burns and McDonnell submitted to the
city contains design and cost requirements for new electrostatic
precipitators (ESP's) to be used in conjunction with high- and
low-sulfur coals. The city is currently considering the plan for
controlling particulate emissions.
Data compiled by the Kansas City Air Pollution Control Labor-
atory.
BLUE VALLEY POWER PLANT 4-67
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f
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TABLE 4-44. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
WITH MAXIMUM RECORDED VALUES NEAR THE BLUE VALLEY POWER PLANT
(Concentration in yg/m^)
Ambient Air Quality Standards
Pollutant
Particulates
Annual geometric
mean
24-hour maximum
so2
Annual arithmetic
mean
24-hour maximum
3-hour maximum
Federal
Primary
IS
260
80
365
Secondary
60
150
1300
State
Primary
60
150
40
159
Maximum
recorded
values
125
14
1975 values.
I
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4.5.5 Analysis of Coal Conversion Potential
2
Coal Availability —
The present source of coal for the Blue Valley plant is in
Oklahoma (Producing District 15). All coal is purchased on a
spot market from Gable Coal Company, United Coal Sales, Associ-
ated Producers, and other Oklahoma coal companies. Since the
Blue Valley plant appears to remain in compliance with the appli-
cable S0» regulations when burning this coal, it is probable that
the plant will continue to burn coal from Oklahoma and Kansas.
Producers in these areas have indicated that a large surplus is
available and production could be expanded in a short time.
If emissions from burning the coal should exceed the ambient
SO- regulation, the current coal could be blended with low-sulfur
coal from southeastern Wyoming. Wyoming producers have indicated
that a small surplus capacity is available for spot purchases.
Table 4-45 presents the average analyses of coal from these
sources.
TABLE 4-45. ANALYSES OF COAL AVAILABLE TO THE
BLUE VALLEY POWER PLANT
Analysis
Oklahoma (Producing
District 15)
Southeastern Wyoming
(Producing District 19)
Heating value,
Btu/lb
Sulfur, %
Ash, %
10,700 - 13,000
1.0 - 7.0
8-20
10,300
0.6
8.0
The Blue Valley plant is located on the Missouri Pacific
lines. The spur leading to the plant can receive a maximum of 12
hopper cars; however, plans call for expansion of the reception
facilities to accommodate approximately 20 hopper cars.
Foster Associates, Inc. Present and Prospective Coal Supply
to the Blue Valley Plant - Independence Power and Light Depart-
ment. May 24, 1976.
BLUE VALLEY POWER PLANT
4-69
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Coal produced in northern Oklahoma and southeastern Kansas
(Producing District 15) would be loaded onto the Kansas City
Southern, St. Louis-San Francisco, Missouri-Kansas-Texas, or
Missouri Pacific railroads, then transferred on the Missouri
Pacific lines for transport from Kansas City to St. Joseph and
delivery to the plant. Railroad officials have indicated that
hopper car availability would be no problem for coal shipments of
25 to 30 hopper cars each. They also said that a leadtime of 9
to 18 months will be necessary if new hopper cars are required.
Coal from the southeastern Wyoming area (Producing District
19} would be transported on the Union Pacific. Hoppers are
readily available on a short-term basis, and several utilities
have idle hopper cars for future mine development. An average
leadtime of 18 months will be required for new hopper cars, if
the current rolling stock proves to be insufficient for future
requirements.
Delivered costs of coal for the Blue Valley plant are shown
in Table 4-46.
TABLE 4-46. ESTIMATED DELIVERED COAL COSTS FOR THE
BLUE VALLEY POWER PLANT
Price (f.o.b. mine),
$/ton
Transportation
cost, $/ton
Total cost, $/ton
Total cost, $/10 Bt
1978 total cost,
$/106 Btu
Northern
Oklahoma
17.00
8.57
25.57
u 1.065a
1.174a'C
Southeastern
Kansas
17.00
6.33
23.33
0.972a
1.07ia'C
Southeastern
Wyoming
11.25
11.50
22.75
1.104b
1.217b'C
Based on 12,000 Btu/lb coal.
Based on 10,300 Btu/lb coal.
Foster Associates values are escalated to 1978 costs.
BLUE VALLEY POWER PLANT
4-70
-------
Technical Factors Affecting Fuel Conversion—
All the boilers are currently firing coal, oil, and gas. If
these units are converted to 100 percent coal firing, Burns and
McDonnell stated that the following new equipment must be pur-
chased: a spur line to handle 30 cars, a thawshed, feeder,
scale, trackmobile, ash pond, maintenance building, and stacks.
Combustion controls must be modified to handle 100 percent coal
firing, and the coal pile must be expanded to handle the extra
coal. The cost for these changes (escalated to 1978 dollars) is
$9,804,000. Additional conversion data are presented in Table
4-47.
4.5.6 Analysis of Methods for Controlling SO., Emissions
The Blue Valley plant is required to limit SO.., emissions to
a 1-hour average of 0.25 ppm or greater once in any 4 days or a
24-hour average of 0.07 ppm once in any 90 days. A modeling
study must be conducted to determine if the plant complies with
the ambient regulation during 100 percent coal firing. If the
emission limits are violated, low-sulfur coal from southeastern
Wyoming can be blended with the coal the plant normally burns
(from Producing District 15) to achieve compliance.
4.5.7 Analysis of Methods for Controlling Particulate
Emissions
Boilers 1, 2, and 3 are each equipped with multicyclone
mechanical collectors with design efficiencies of 85, 85, and
90.3 percent, respectively. These boilers are not in compliance
with the particulate emission regulation when either high- or
low-sulfur coal is burned. Compliance can be attained through
installation of new ESP's.
The estimated capital cost of new ESP's is $14,449,000
($141.66/kW). The annualized operating cost is estimated to be
$1,434,000 (3.15 mills/kWh). Costs are based on a collection
efficiency of 97.72 percent, which is needed to meet the parti-
culate regulation of 0.24 lb/10 Btu. Plate areas required for
new ESP's on Boilers 1, 2, and 3 are 18,000, 18,000, and 40,500
ft , respectively.
BLUE VALLEY POWER PLANT 4-71
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f
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z
1-3
TABLE 4-47. COAL CONVERSION DATA FOR THE BLUE VALLEY POWER PLANT
Boiler
No.
1
2
3
Total
Capacity
factor
(1975) ,
%
36.1
59.5
53.4
Fuel consumption
Type
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Quantity/yr
20,882 tons
1,000 bbl
460,134 103 ft3
30,368 tons
1,100 bbl
944,066 103 ft3
79,494 tons
5,950 bbl
1,537,036 103 ft3
Coal conversion data h
Conv. cost,
$
9,804,000°
Coal usage,
tons/yr
21,000
43,000
71,000
135,000
a Information from Power Plant Survey Form (Appendix E) .
k Additional coal required for 100% coal firing based on 10,907 Btu/lb,
2.47% sulfur, and 13.5% ash.
c Cost taken from the Burns and McDonnell report for the Blue Valley Power
Plant and escalated to 1978 dollars.
i
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to
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4.5.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to coal
firing, the recommended strategy is to continue to burn the
current coal supply until it can be determined whether the boil-
ers are in compliance with the ambient S02 regulation and to
control particulate emissions by installing new ESP's. The
capital and operating costs of the recommended strategy are shown
in Table 4-48. Emission rates and regulations applicable to the
recommended strategy are shown in Table 4-49.
BLUE VALLEY POWER PLANT 4-73
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03
f
G
M
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f
M
TABLE 4-48. ESTIMATED COSTS OF EMISSION CONTROLS
AT THE BLUE VALLEY POWER PLANT - 1978
i
M
to
f
>
2
Emission control
alternative
SO- control
Limestone scrubbing
Sodium solution regenerable
Particulate control
Electrostatic precipitator
installation*5
Boilers 1, 2, and 3
Flue gas conditioning
Time
required,
months
NA
36
NA
Capital cost
106 S
14 .449
SAW
141.66
Annualized cost
Fuel
mills/kWh
0.62
O i M
mills/kwh
0.90
Fixed
mills/kWh
1.63
Total f
mills/kWh
3.15
10" S
1.434
8 ESP design based on coal with 2.47% S, 13.5% ash, and 10,900 Btu/lb.
b Costs are in January 1978 dollars; they have not been escalated through project completion and do not include replacement
power.
NA - Not applicable.
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CO
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f
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2
TABLE 4-49. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE BLUE VALLEY POWER PLANT
Fuel type
BOILER 1
Alternate fuel
Coal
BOILER 2
Alternate fuel
Coal
BOILER 3
Alternate fuel
Coal
Sulfur dioxide
Actual
emission rate
lb/106 Btu
4.30
4.30
4.30
tons/yr
1969
3444
7075
Allowable
emission rate
lb/106 Btu
b
b
b
ton3/yr
b
b
b
Particulate
Actual a
emission rate
lb/106 Btu
0.105
(1.58)C
0. 105
(1.58)
0. 105
(1.58)
tons/yr
110
(722)c
192
(1263)
395
(1678)
Allowable
emission rate
lb/106 Btu
0.24
0.24
0. 24
tons/yr
251
439
903
a Based on a coal analysis of 10,907 Btu/lb, 2.47% sulfur, and 13.5% ash; and new ESP's each with a design efficiency of 97.72%.
b Ambient Air Fenceline Standard 1-hour average of 0.25 ppm or greater in any 4 davs; or 24-hour average of 0.07
ppm or greater once in 90 days.
c Numbers in parentheses indicate potential emissions resulting from coal conversion without the installation of additional
control equipment.
I
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4.6 CROMBY PLANT
4.6.1 Plant Description
The Cromby power plant (owned and operated by the Phila-
delphia Electric Company) is located on the west bank of the
Schuylkill River in Phoenixville, Pennsylvania, in Chester County.
This area is part of the metropolitan Philadelphia Interstate Air
Quality Control Region (AQCR 045).
The two boilers at Cromby are capable of firing coal or
residual oil on a continuous basis. Boiler 1 is currently firing
coal; therefore, only Boiler 2 is evaluated for conversion to
coal firing. Boilers 1 and 2 were placed in commercial operation
in 1954 and 1955, respectively. Boiler 1 is a pulverized-coal-
fired unit that is rated at 187.5 MW. Boiler 2 is a pulverized-
coal-fired unit that is rated at 230 MW. Boiler 1, manufactured
by Babcock and Wilcox, is front-firing; and Boiler 2, manufac-
tured by Combustion Engineering, is tangential-firing. Each
boiler is equipped with a mechanical collector and an electro-
static precipitator (ESP) and exhausts through an individual 300-
ft stack.
Additional unit design and operating data are presented in
Table 4-50. A site plan of the plant is shown in Figure 4-11.
4.6.2 Fuel Supply and Characteristics
Boiler 1 fires coal, and Boiler 2 fires residual oil. In
1975 Boiler 2 fired 1,221,000 bbl of residual oil, which was
obtained from Amerada Hess Corporation and other suppliers within
the Philadelphia area. Coal is primarily supplied by mines in
northern West Virginia (Producing District 3) and the West
Virginia Panhandle (Producing District 6). The latest available
fuel analyses and costs are presented in Tables 4-51 and 4-52.
CROMBY POWER PLANT 4-76
-------
TABLE 4-50. DESIGN AND OPERATING DATA FOR THE CROMBY POWER PLANT
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input0, 10 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
—s — •
Coal firing3
1
187.5
7229
54
1
B&W
1954
48.5
1193
300
435,000
250
ESP and
mechanical
collector
2
230.0
5588
36
2
CE
1955
67.5
1661
300
685,000
240
ESP and
mechanical
o
50
O
13
i
w
13
B&W - Babcock and Wilcox; CE - Combustion Engineering
Based on coal heating value of 12,300 Btu/lb.
I
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n
1
HEATING BOILER HOUSE
STACKS TRANSFER TOWER
J 132KV SUB-STATION
DQ
"^TRANSFORMERS
OQ
SCHUYUILL RIVER
I
^J
00
Figure 4-11. Site plan of the Cromby power plant.
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TABLE 4-51. ANALYSES OF FUEL BURNED AT THE CROMBY POWER PLANT
Analysis
Heating value
Sulfur
Ash
Coala
12,382 Btu/lb
2.6%
11.5%
oiia
147,447 Btu/gal
0.4%
Information from Power Plant Survey Form (Appendix F).
TABLE 4-52. COSTS OF FUEL AT THE CROMBY POWER PLANT
Type
of
Purchase
Fuel
cost,
a
5/10
6
Btu
Contract
Contract
1.395 (Coal)
2.336 (Oil)
a Information from Electrical Week magazine, December 1977.
4.6.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 045
as Priority I with respect to emissions of particulates and
sulfur oxides.
The current particulate emission limitation applicable to
the plant is 0.10 lb/10 Btu heat input (Pennsylvania's Air
Quality Regulations). Sulfur dioxide (S0~) emissions are limited
c *•
to 0.6 lb/10 Btu heat input [Section 123.22 (iii)].
Table 4-53 summarizes emission rates and applicable regula-
tions for Boilers 1 and 2 at the Cromby plant.
Air Quality Monitoring Data—
No ambient particulate or ambient SO2 monitoring data are
currently available. Federal and State ambient air standards
applicable to the Cromby power plant are presented in Table 4-54.
CROMBY POWER PLANT
4-79
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o
»
o
3
CB
K
TABLE 4-53. EMISSION RATES AND APPLICABLE REGULATIONS FOR
CURRENT FUEL USAGE AT THE CROMBY POWER PLANT
i
w
JO
Fuel type
BOILER 1
Current fuel
Coal
Oil
BOILER 2
Current fuel
Oil
Sulfur dioxide
Actual emission
rate3
lb/106 Btu
3.99
0.43
0.43
tons/yr
16,944
32
1610
Allowable
emission rate
lb/106 Btu
0.6
0.6
0.6
tons/yr
2548
45
2247
Particulate
Actual emission
rate3
lb/106 Btu
0.16b
0.05
0.05
tons/yr
671b
4
205
Allowable
emission .rate
lb/106 Btu
0.10
0.10
0.10
tons/yr
419
8
410
a Baaed on an analysis of 2.5% sulfur, 11.5% ash, and 12,382 Btu/lb for coal; 0.4% sulfur and 147,447
Btu/gal for oil: and AP-42 emission factors.
b Particulate emissions from coal include a combined efficiency of 98% for the existing control equipment on
Boiler 1.
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o
50
O
TABLE 4-54. FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
APPLICABLE TO THE CROMBY POWER PLANT
(Concentration in
O
S
w
£
z
Pollutant
Particulates
Annual geometric mean
Maximum 24-hour average
so2
Annual arithmetic mean
Maximum 2 4 -hour average
Maximum 3-hour average
Ambient Air Quality Standards
Federal
Primary
75
260
80
365
Secondary
60
150
1300
State
Primary
75
260
80
365
Secondary
60
150
1300
I
00
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4.6.4 Plant Programs for Complying with Emission Regulations
Boiler 1 at the Cromby plant is presently firing coal under
a "consent order" from the State of Pennsylvania. The consent
order incorporates a Phase I and Phase II program. Phase I
involves installation of an S02 scrubbing system at the Phila-
delphia Electric's Eddystone plant. Once the system is proved to
be operational, Phase II must be implemented. Phase II involves
installation of a similar scrubbing system on Boiler 1 at Cromby
to comply with the particulate and S02 emission regulations.
When Boiler 2 fires residual oil, it complies with both the
particulate and S0? emission regulations. In the event that
Boiler 2 is converted to coal firing, the unit will violate the
current regulations. The plant has not yet formulated plans for
compliance if Boiler 2 is converted to coal firing.
4.6.5 Analysis of Coal Conversion Potential
Coal Availability --
The coal fired at the Cromby plant is purchased under
contract from sources in northern West Virginia and the West
Virginia Panhandle (Producing Districts 3 and 6). Coal could
also be obtained from eastern Kentucky and southern West Virginia
(Producing Districts 7 and 8). Analyses of these coal supplies
are presented in Table 4-55.
TABLE 4-55. ANALYSES OF COAL AVAILABLE TO THE
CROMBY POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Northern
West Virginia
12,400 - 13,000
2.5 - 2.8
8-12
Eastern Kentucky and
southern West Virginia
12,000 - 13,000
1.0 - 1.5
6-12
Foster Associates, Inc. Analysis of the Present and Prospective
Coal Supply to the Cromby Plant - Philadelphia Electric Company.
September 9, 1976.
CROMBY POWER PLANT
4-82
-------
The Cromby plant receives coal from the former Penn Central
and Reading Company rail lines. Both of these rail lines are now
operated as a part of Consolidated Rail Corporation (ConRail).
The coal is loaded onto the Chessie System and then transferred
to ConRail for delivery to the plant. ConRail should have no
major problems transporting the present coal supplies or in-
creased volumes.
Estimated costs of the delivered coal are shown in Table
4-56. Rail transportation costs are based on tariffs currently
in effect and are estimated for coal produced in producing
Districts 3 and 8. If the Cromby plant were converted to total
coal firing, the annual coal requirements would probably be large
enough for the plant to qualify for a unit train tariff. A unit
train tariff negotiated with the carrier could result in lower
transportation costs.
TABLE 4-56. ESTIMATED DELIVERED COAL COSTS FOR THE
CROMBY POWER PLANT
Price (f .o.b. mine) , $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/106 Btu
Northern
West Virginia
17.00
9.90
26.90
1.085a
1.196a'C
Eastern
Kentucky
22.00
12.60
34.60
1.418b
1.563b'C
Based on a coal with a heating value of 12,400 Btu/lb.
Based on a coal with a heating value of 12,200 Btu/lb.
Foster Associates values escalated to 1978 dollars.
CROMBY POWER PLANT
4-83
-------
Technical Factors Affecting Fuel Conversion—
Boiler 2 was originally designed to fire coal, but has been
completely converted to fire oil. Conversion back to coal
firing would require inspecting, cleaning, and repairing or
replacing such items as the coal burners, mills, ash handling
systems, ESP's, combustion controls, and tube shields on the
superheater tubes.
The Cromby plant has estimated at cost of $60,000 to convert
Boiler 2 to coal firing. Coal conversion data for Boiler 2 are
presented in Table 4-57.
4.6.6 Analysis of Methods for Controlling SCs Emissions
Low-sulfur Coal—
The plant could meet the S02 emission regulation by firing
0.38 percent sulfur (12,000 Btu/lb) coal. Coal with these
characteristics is not available to the Cromby plant.
Flue Gas Desulfurization (FGD)—
A limestone scrubbing and sodium solution regenerable
system are evaluated for control of S02 emissions at the Cromby
plant. Two cost estimates were made for each system based on
coal with sulfur contents of 1.1 and 2.8 percent. The capital
costs of both systems while burning the lower-sulfur coal are
lower than the costs while burning the higher-sulfur coal. The
annual cost of the sodium solution system is also lower when the
1.1 percent sulfur coal is burned. The annual cost of the lime-
stone system, however, is lower when the higher-sulfur coal is
burned because of the greater fuel credit. Because these esti-
mates are the most cost-effective, the following cost estimates
are based on the sodium solution regenerable system firing 1.1
percent sulfur coal and the limestone system firing 2.8 percent
sulfur coal.
Capital cost of retrofitting Boiler 2 with a limestone
scrubbing system when firing 2.8 percent sulfur coal, including a
coal conversion cost of $60,000, is $21,584,000 ($93.84/kW).
CROMBY POWER PLANT 4-84
-------
o
TABLE 4-57. COAL CONVERSION DATA FOR THE CROMBY POWER PLANT
Boiler
No.
1
2
Total
Capacity
factor
(1975) ,
%
54
36
Fuel consumption
Type
Coal
Oil
Oil
Quantity/yr
343,000 tons
24,000 bbl
1,221,000 bbl
Coal conversion data
Conv. cost,
$
60,000
60,000b
Coal usage,"
tons/yr
NA
289,000
289,000
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w
50
I
i-3
Based on a heat rate of 9789 Btu/kWh and 12,300 Btu/lb coal.
Based on plant estimate escalated to 197S dollars.
NA - Not applicable.
i
CO
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Annualized operating costs, including a fuel credit of $9,099,000
(12.54 mills/kWh), is $999,000 (1.38 mills/kWh). The system is
based on 86 percent removal capability.
Capital cost of the sodium solution regenerable system while
firing 1.1 percent sulfur coal is estimated to be $23,750,000
($103.26/kW), which includes a coal conversion cost of $60,000.
Annualized costs, which include trucking costs, are offset by the
fuel credit (in switching from oil to high-sulfur coal firing),
and results in a net annual cost of $473,000 (0.65 mills/kWh).
This system is based on 65 percent removal capability.
4.6.7 Analysis of Methods for Controlling Particulate Emissions
Boiler 2 is equipped with an American Blower mechanical
collector and a Research-Cottrell ESP, which have design effi-
ciencies of 80 and 98 percent, respectively. The ESP was put
into operation in 1955 and was designed for use with high-sulfur
coal. Total plate area is 25,650 ft . Boiler 2 will not comply
with the particulate emission regulation when high- or low-sulfur
coal are fired. Compliance can be accomplished by installing a
2
new ESP (which would have a required plate area of 124,000 ft
and a design efficiency of 98.8 percent) to meet the 0.10 lb/10
Btu particulate regulation when firing 2.8 percent sulfur coal.
This control alternative will not meet the SO2 emission regula-
tion.
Capital cost of the new ESP is estimated to be $4,139,000
($18.00/kW), which includes coal conversion costs. Annualized
operating costs, which include bottom and fly ash removal, are
offset by the fuel credit (in switching from oil to low-sulfur
coal firing) and result in a net annual credit of $6,142,000
(8.47 mills/kWh).
Particulate compliance can be accomplished when high-sulfur
coal is fired by installing venturi scrubbers in conjunction with
the FGD system. Capital cost of the scrubber installation is
included in the FGD costs.
CROMBY POWER PLANT 4~86
-------
4.6.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to coal
firing, the recommended strategy is to fire 1.1 percent sulfur
coal and install a sodium solution regenerable system, or fire
2.8 percent sulfur coal and install a limestone scrubbing system
on Boiler 2 to comply with the applicable SO,, and particulate
regulations.
Cost assessments for the alternatives evaluated are pre-
sented in Table 4-58. Emission rates and regulations applicable
to the recommended strategy are shown in Table 4-59.
CROMBY POWER PLANT 4-87
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o
§
TABLE 4-58. ESTIMATED COST OF EMISSION CONTROL OPTIONS
AT THE CROMBY POWER PLANT - 1978
13
O
S
w
£
z
Emission control
alternative
Combined SO, /Participate
« *
Controls, Boiler 2
Low-sulfur coal
Limestone scrubbing
Sodium solution regenerable
a
Particulate control. Boiler 2
Electrostatic precipitator
installation
Flue gas conditioning
Time
required,
months
NA
36
36
24
NA
Capital cost
106 S
21.58
23.75
4.14
S/kW
93.84
103.26
18.00
Annualized cost
Fuel,
mills/kWh
(12.54)
(9.17)
(12.04)
OfcM,
mills/kWh
8.06
3.38
2.96
Fixed,
mills/kWh
5.86
6.44
1.11
Total ,
mills/kWh
1.38
0.65
(8.47)
10b S
1.00
0.47
(6.14)
3 Numbers in parentheses are credits.
b Limestone system costs are based on coal with 2.8% S, 12.0% ash, and 12,400 Btu/lb; sodium solution regenerable
system costs are based on coal with 1.1% S, 12.0% ash, and 12,200 Btu/lb.
0 Costs are in January 1978 dollars; they have not been escalated through project completion and do not include
replacement power.
d ESP design on Boiler 2 is based on coal with 2.8% S. 12.0% ash, and 12,400 Btu/lb.
NA - Not applicable.
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o
»
o
3
DO
TABLE 4-59. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE CROMBY POWER PLANT
w
JO
£
25
—
Fuel type
BOILER 2
Alternate fuel
Coalc
Sulfur dioxide
Actual
lb/106 Btu
0.6
(1.71)
tons/yr
2,119
(6,040)
Allowable
emission rate ,_
lb/106 Btu
0.6
tons/yr
2,119
Particulate
Actual
emission rate3 h
lb/106 Btu
0.10
(0.711
tons/yr
350
(2,4881
Allowable
emission rate ,
n TT .b
lb/106 Btu
0.10
cons / y '
350
I
00
vo
a Numbers in parentheses indicate emissions resulting from coal conversion without the installation of additional control
equipment (i.e., combined particulate removal efficiency of 91.6%).
b Based on estimated annual coal consumption and emission factors.
c Emissions based on a coal analysis of 1.1» S, 12.0* ash, and 12,200 Btu/lb; emission factors: and use of an FGD system
with venturi scrubber for SO2 and particulate emission control.
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4.7 HOWARD M. DOWN
4.7.1 Plant Description
The Howard M. Down plant (owned and operated by the City of
Vineland Electric Utility) is located in Vineland, Cumberland
County, New Jersey. This area is part of the New Jersey Intra-
state Air Quality Control Region (AQCR 150).
The H. M. Down plant consists of five boilers, but only
Boiler 10 is evaluated for conversion to coal firing. Boilers 4,
7, 8, 9, and 10 have a total maximum continuous generating
capacity of 70.5 MW. Boiler 4, manufactured by Babcock and
Wilcox, is equipped to fire residual oil and is rated at 9.0 MW.
Boilers 7, 8, and 9, all spreader stoker units, are designed to
fire coal and residual oil and are rated at 7.5, 12.5, and 16.5
MW, respectively. Boiler 10, manufactured by Erie City Iron
Works, is a pulverized-coal-fired unit capable of firing coal and
residual oil; it is rated at 25.0 MW. Boilers 7, 8, 9, and 10
are equipped with mechanical collectors that have design effi-
ciencies of 92.7, 92.8, 90.0, and 78.0 percent, respectively.
Boiler 10 is also equipped with an electrostatic precipitator
(ESP). All units exhaust through individual 138-ft stacks.
Additional unit design and operating data are presented in
Table 4-60. A site plan of the plant is shown in Figure 4-12.
4.7.2 Fuel Supply and Characteristics
All of the boilers at the H. M. Down plant currently fire
residual oil. Oil is supplied by the Pedroni Oil Company in
Paulsboro, New Jersey. In 1975, Boiler 10 fired 187,710 bbl of
oil. Coal was last purchased in 1973 and 1974 from the Island
Creek Coal Sales Company in West Virginia and Crown Coal and Coke
Company in Pennsylvania. The latest available oil analysis and
costs are presented in Tables 4-61 and 4-62.
H. M. DOWN POWER PLANT 4-90
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a
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TABLE 4-60. DESIGN AND OPERATING DATA FOR THE HOWARD M. DOWN POWER PLANT
Item
Coal firing
f
-3
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975), %
Served by Stack No.
Boiler .manufacturer
Year placed in service
Max. coal consumption, tons/h
/-
Max. heat input, 10° Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
10
25.0
6346
43.0
10
ERIG
1970
13.3
319
138
100,800
270
Mechanical collector and
ESP
Information from Power Plant Survey Form (Appendix G).
ERIG - Erie City Iron Works, Inc.
Based on coal heating value of 12,000 Btu/lb.
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D
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i
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VD
WEST AVENUE
ASH
ASH
STACK SILO
D
ESP
TURBINE
HALL
BOILER ! £
WOM | y <
I ri
BOILER
BOILER 18
BOILER »9
TRANSFORMER
CONVEYOR
BOILER flO
SUBSTATION
g
SPRAY
POND
D
TRACK HOPPER
HOUSE
G
7
| OOO|
8
COOLING
TOWERS
D
O
OIL TANKS
SECOND STREET
10 9
O
O
O
COOLING
TOWERS
O
0
0
NATIONAL
FREIGHT
LINES
ELECTRICAL
SERVICE
BUILDING
Figure 4-12. Site plan of the H.M. Down power plant.
-------
TABLE 4-61. ANALYSIS OF FUEL BURNED AT THE
H. M. DOWN POWER PLANT
Analysis
Heating value
Sulfur
Residual oil
144,660 Btu/gal
0.7%
a Information from Power Plant Survey Form (Appendix G).
TABLE 4-62. COST OF FUEL AT THE H. M. DOWN POWER PLANT
Type of purchase
Contract
Fuel cost,3 $/10
Btu
Oil
2.213
a
Information from Electrical Week magazine, December 1977.
4.7.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 150
as Priority III with respect to particulate emissions, and
Priority IA with respect to sulfur oxide emissions.
The current particulate emission regulation (Title 7, Chap-
ter 27, Subchapter 4, Section 4.2 of the New Jersey Regulations)
limits emissions from Boiler 10 to 0.10 lb/10 Btu heat input.
Sulfur dioxide (SO-) emissions are limited to 1.5 lb/10 Btu heat
input [Subchapters 9 and 10, Section 9.2(b)].
Table 4-63 summarizes emission rates and applicable regula-
tions for the H. M. Down power plant.
Air Quality Monitoring Data—
From.March 22 to June 28, 1976, ambient S02 monitoring data
were taken at a mobile van located at the Vineland State Hospital,
The monitoring site is about 1 mile from the plant. Measurements
show that the State of New Jersey ambient secondary S02 standard
was violated on June 16 at the monitoring site.
H. M. DOWN POWER PLANT 4-93
-------
OS
s
o
o
TABLE 4-63. EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT FUEL USAGE
AT THE HOWARD M. DOWN POWER PLANT
i
f
>
25
Fuel type
BOILER 10
Current fuel
Oil3
Sulfur dioxide
Actual
emi ss ion irate
lb/106 Btu
0.75
tons/yr
433
Al lowable
emission rate
lb/106 Btu
1. 10
tons/yr
635
Par ticulate
Actual
emission rate
lb/106 Btu
0.05
tons/yr
31.5
Allowable
emission rate
lb/106 Btu
0.10
tons/yr
63
Based on 1975 fuel usage, an oil analysis of 146,660 Btu/gal and 0.7% S, and AP-42 emission factors.
I
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£>.
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A maximum 24-hour average of 0.103 ppm SC>2 and a maximum 1-
hour average of 0.200 ppm S02 were recorded. No particulate
monitoring data are available.
Table 4-64 summarizes the Federal and State ambient air
quality standards and maximum values recorded near the plant.
4.7.4 Plant Programs for Complying with Emission Regulations
Boiler 10 complies with both the particulate and SG>2 emis-
sion regulations when it fires oil. If Boiler 10 is converted to
coal firing, the unit will violate current particulate emission
regulations when firing low-sulfur coal. The plant has asked the
State of New Jersey to relax its sulfur-in-fuel limitation that
applies to coal firing. To date no official ruling has been
implemented. Boiler 10 should achieve compliance with the par-
ticulate regulation when firing 1.5 percent sulfur coal. En-
gineering Science, Inc., is conducting a long-range modeling
study on AQCR 150 to evaluate the particulate and SG>2 regulations.
4.7.5 Analysis of Coal Conversion Potential
Coal Availability—
The boilers at the H. M. Down Plant do not burn coal. If
Boiler 10 is converted to total coal firing, it would require
approximately 50,000 tons of coal annually. The plant must
comply with S02 regulations, which limit emissions to 1.5 lb/106
Btu heat input. This regulation would require that the plant
burn a coal with a sulfur content of approximately 0.9 percent
(based on a heat content of 12,000 Btu/lb).
Coal was previously obtained from southern West Virginia and
eastern Kentucky (Producing Districts 7 and 8). These areas
could supply coal to the H. M. Down plant if Boiler 10 is re-
quired to convert back to coal firing. Characteristics of the
coal are presented in Table 4-65. Coal is available that would
Foster Associates, Inc. Present and Prospective Coal Supply to
the Howard M. Down plant - City of Vineland Electric Utility
September 9, 1976.
H. M. DOWN POWER PLANT 4-95
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a
o
o
M
f
>-3
TABLE 4-64. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
WITH MAXIMUM VALUES RECORDED NEAR THE HOWARD M. DOWN POWER PLANT
(Concentration in yg/m )
Pollutant
Particulates
Annual geometric
mean
24-hour maximum
so2
Annual arithmetic
mean
24-hour maximum
3-hour maximum
Ambient Air Quality Standards
Federal
Primary
75
260
80
365
Secondary
60
150
1300
State
Primary
75
260
80
365
Secondary
60
260
1300
Maximum
recorded
values
NA
268
a 1976 values.
NA - No particulate monitoring data are available.
I
vo
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enable the plant to comply with the S02 regulation; however, the
cost of this coal would be higher than the normal 1.0 percent
sulfur coal.
TABLE 4-65. ANALYSES OF COAL AVAILABLE TO THE
HOWARD M. DOWN POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Eastern Kentucky (Producing
District 8)
12,000 - 13,000
0.9 - 1.5
6-12
Coal mined in Producing Districts 7 and 8 would be loaded
onto the Chessie System (B&O - C&O) and then transferred to Con-
Rail at Philadelphia for final delivery to the plant. Both road-
bed and hopper car capacity of these carriers would be adequate
to meet the demands of the H. M. Down plant. Table 4-66 presents
delivered costs of coal based on tariffs presently in effect for
single-car shipments originating in Producing District 8.
TABLE 4-66. ESTIMATED DELIVERED COAL COSTS FOR THE
HOWARD M. DOWN POWER PLANT
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/106 Btu
Eastern
18.25a
12.74
30.99
1.291°
1.423C'd
Kentucky
25.00b
12.74
37.74
1.573°
1.733C'd
1.5 percent sulfur coal.
0.9 percent sulfur coal.
Based on a coal with a heating value of 12,000 Btu/lb.
Foster Associates values escalated to 1978 dollars.
H. M. DOWN POWER PLANT
4-97
-------
Technical Factors Affecting Fuel Conversion—
Reconverting Boiler 10 to coal firing would require no major
additions on equipment changes to the coal handling, coal firing,
and ash handling systems. A new wastewater treatment system
would be required, and parts for the pulverizers would have to be
replaced. PEDCo estimates these costs to be $205,000. Table 4-
67 presents fuel usage data on which these costs are based.
4.7.6 Analysis of Methods for Controlling S02 Emissions
Low-sulfur Coal—
Boiler 10 could meet the SO- emission regulation by firing
low-sulfur coal from eastern Kentucky (Producing District 8).
Compliance is based on firing coal having an analysis of 0.90
percent sulfur, 12.0 percent ash, and a heating value of 12,000
Btu/lb. Since complying sulfur coal is available to the H. M.
Down plant, no other methods for controlling S02 emissions are
evaluated (such as the sodium solution regenerable and limestone
scrubbing systems).
4.7.7 Analysis of Methods for Controlling Particulate Emissions
Boiler 10 is equipped with a Research-Cottrell multicyclone
mechanical collector and an ESP that have design efficiencies of
78.0 and 91.0 percent, respectively. The ESP has a total plate
area of 12,100 ft and is designed for use with 2.34 percent
sulfur coal. If Boiler 10 is converted to coal firing, the unit
would violate the particulate emission regulation when firing
complying-sulfur coal (0.9 percent). Particulate emissions can
be brought into compliance by installing an add-on ESP having a
design efficiency of 96.54 percent and a plate area of 38,000
2
ft . Capital cost of the add-on ESP is estimated to be $2,354,000
($94.16/kW). The annualized operating cost is estimated to be
$112,000 (1.19 mills/kWh), which includes a fuel credit of
$479,000 (5.09 mills/kWh) resulting from conversion from oil to
coal.
H. M. DOWN POWER PLANT 4-98
-------
ffi
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TABLE 4-67. COAL CONVERSION DATA FOR THE HOWARD M. DOWN PLANT
Boiler
No.
10
Capacity
factor
(1975),
%
43.0
Fuel consumption3
Type
Oil
Barrels/yr
187,710
Coal conversion data w
Conv. cost,
$
205,000
Coal usage,"
tons/yr
50,000
I
vo
Information from Power Plant Survey Form (Appendix G).
Additional coal required for 100% coal firing (12,000 Btu/lb).
As reported by the plant, esculated to 1978 dollars.
-------
The plant has asked the State of New Jersey to relax its
sulfur-in-fuel limitation that applies to coal firing in Boiler
10. To date no official ruling has been implemented. If
Boiler 10 is permitted to fire 1.5 percent sulfur coal, the
current control equipment should enable it to comply with the
particulate regulation. Stack tests will be necessary to ensure
compliance. Based on current fuel costs, the annual credit of
firing 1.5 percent sulfur coal instead of oil is $783,000 (8.32
mills/kWh).
4.7.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to coal
firing, the recommended strategy is to fire 0.9 percent sulfur
coal in Boiler 10 and install an add-on ESP to comply with ap-
plicable SO™ and particulate emission regulations.
Cost assessments for the control strategies are summarized
in Table 4-68. Emission rates and regulations applicable to the
recommended strategy are shown in Table 4-69.
H. M. DOWN POWER PLANT 4-100
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33
•
3
TABLE 4-68.
ESTIMATED COST OF EMISSION CONTROL OPTIONS AT THE
HOWARD M. DOWN POWER PLANT - 1978
D
O
13
O
s
w
£
a
Emission control
alternative
Combined SO2/particulate
controls
Limestone scrubbing
Sodium soln. regenerable
Particulate control
Electrostatic precipi-
tator installation
0.9 percent sulfur
coaia-e
1.5 percent sulfur
coaie
Flue gas conditioning
Time
requi red ,
months
NA
i
36
NA
Capital cost3
$ 106
2.35-1
0.205
SAW
94.16
8.20
Annualized cost
Fuel,
mills/kWh
(5.09)
(9.04)
O&M,
mills/kwh
2.64°
0.72C
Fixed ,
mills/kwh
3.64
Total
mills/kwh
1.19
(8.32)
S 10"
0.112
(0.783)
3 Includes coal conversion cost of $205,000.
Numbers in parentheses represent credits.
c Includes trucking cost of $68,000.
d ESP design on Boiler 10 is based on coal having an analysis of 0.90% S, 12.0% ash, and 12,000 Btu/lb.
e Costs are in January 1978 dollars; they have not been escalated through project completion and do not
include replacement power.
NA - Not applicable.
i
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DC
3
a
o
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13
TABLE 4-69. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE HOWARD M. DOWN POWER PLANT
Fuel type
BOILER 10
Alternate fuel
Coal3
Coalb
Sulfur dioxide
Actua 1
emission rate
lb/10" Btu
1-43
(1.43)c
2.38
tons/yr
893
(B98)c
1425
Allowable
emission rate
lb/106 Btu
1.50
1.50
tons/yr
942
898
Particulate
Actual
emission rate
lb/10° Btu
0.10
(0.636)c
0.10
tons/yr
60
(382)c
58
Allowable
emission rate
lb/106 Btu
0.10
0.10
tons/yr
60
58
a Based on coal having an analysis of 12,000 Btu/lb, 0.9% sulfur, and 12.0% ash and AP-42 emission factors. Particulate
emissions from coal burning include an overall collection efficiency of 98.82% from an add-on ESP and the existing
ESP and multicyclone.
b Based on coal having an analysis of 12,000 Btu/lb, 1.5% sulfur, and 12.0% ash and emission factors. Particulate
emissions from coal burning include a combined collection efficiency of 98.86% from the existing ESP and multicyclone.
c Numbers in parentheses represent potential emissions resulting from a conversion to total coal firing without the
installation of additional control equipment.
O
to
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4.8 FOX LAKE PLANT
4.8.1 Plant Description
The Fox Lake power plant (of the Interstate Power Company)
is located on the south bank of Fox Lake near Sherburn, Minnesota.
This area is part of the Southwest Minnesota Intrastate Air
Quality Control Region (AQCR 133).
Fox Lake has three pulverized-coal Riley Stoker boilers, 1
through 3, which were placed in service in 1950, 1950, 1962,
respectively, and have continuous generating capacities of 12,
12, and 86 MW. Boilers 1 and 2 exhaust through a single 141-ft
stack. Boiler 3 exhausts through its own 142-ft stack. All of
the boilers can fire coal, fuel oil, or natural gas; however,
pulverizer limitations cause Boiler 3 to be derated 65 percent
(86 to 30 MW) when firing coal. None of the boilers has sulfur
dioxide (SO-) or particulate emission control equipment.
The evaluation of the Fox Lake plant is limited to Boiler 3.
Table 4-70 presents additional unit design and operating data on
this boiler, and Figure 4-13 shows a site plan of the entire
plant.
4.8.2 Fuel Supply and Characteristics
Boiler 3 at the Fox Lake plant is firing low-sulfur coal and
natural gas, either in combination or separately. In 1975 Boiler
3 fired 1.985 billion cubic feet of natural gas and 6934 tons of
coal. Coal for the plant is purchased under long-term contract
with Westmoreland Resources and is supplied by their Big Horn
County, Montana, mines. The latest available fuel analyses and
fuel costs are presented in Tables 4-71 and 4-72.
FOX LAKE POWER PLANT 4-103
-------
FOX LAKE POWER :
f1
*
TABLE 4-70. DESIGN AND OPERATING DATA FOR THE FOX LAKE POWER PLANT
Item
Boiler number
Generating capacity, MVr
Hours of operation (1975)
Average capacity factor (1975)
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input, 106 Btu/h
Stack height, ft above grade
Flue gas rate maximum, acfm
Flue gas temperature, °F
Emission controls
Coal firing3
3
86
7826
38.0
3
Riley
1962
20.0
860
142
295,000
285
None
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O
a Information from Power Plant Survey Form (Appendix H).
b In the event of 100% coal firing, pulverized capacity could be increased
so that the 86 MW could be achieved.
c Riley Stoker Corporation.
d Based on heat rate of 10,000 Btu/kWh.
-------
3
X
REGULATOR
! AND METERING HOUSE
i
i-1
o
Figure 4-13. Site plan of the Fox Lake power plant.
-------
TABLE 4-71. ANALYSES OF FUEL USED AT THE FOX LAKE POWER PLANT
Analysis
Heating value
Sulfur
Ash
Coala
8450 Btu/lb
0.73%
9.09%
Gasa
1000 Btu/ft3
a Information from Power Plant Survey Form (Appendix B).
TABLE 4-72. COSTS OF FUEL AT THE FOX LAKE POWER PLANT
Type of purchase
Contract
Interruptible
Fuel cost
1.481
1.111
,a $/106 Btu
(coal)
(gas)
a Information from Electrical Week, magazine, October, 1977.
4.8.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 133
as Priority III with respect to emissions of particulates and
sulfur oxides.
Section (2)(bb)(i) of Regulation No. APC-4 of the Minnesota
Regulations limits particulate emissions at the Fox Lake plant to
0.60 lb/106 Btu heat input. Section (2)(aa) of this regulation
limits sulfur dioxide (S00) emissions to 4.0 lb/10 Btu heat
fi
input if a solid fuel is burned and 2.0 lb/10 Btu heat if a
liquid fuel is burned.
Table 4-73 summarizes emission rates and applicable regula-
tions for fuel currently fired at the Fox Lake plant.
FOX LAKE POWER PLANT
4-106
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o
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tr1
TABLE 4-73.
EMISSION RATES AND APPLICABLE REGULATIONS USING CURRENT FUELS
AT THE FOX LAKE POWER PLANT
Fuel type
BOILER 3
Current fuel
Gas
Coal
Sulfur dioxide
Actual
emission r'ate
lb/106 Btu
0.0006
1.64
tons/yr*3
<1
96
Al lowable
emission rate
lb/106 Btu
2.0
4.0
tons/yr"
2,000
235
Part iculate
Actual
emission rate3
lb/106 Btu
0.01
9.14
ton3/yrb
10
536
Allowable
emission rate
lb/106 Btu
0.6
0._6
tons/yrb
594
35
Based on 0.73% sulfur, 9.09% ash and 8450 Btu/lb coal, 1000 Btu/ft3 natural gas, and emission factors
from AP-42.
Based on 1975 fuel consumption.
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Air Quality Monitoring Data —
Data from sampling conducted by Sierra Research Corporation
for a 7-day period (March 20-26) in 1973 indicate that State and
Federal primary and secondary ambient particulate standards were
not exceeded at the monitoring site. Particulate sampling was
conducted at only one location slightly less than 1 kilometer
east of the plant. The average concentration for four 24-hour
samples (measured by Hi-vol) was 40.2 ug/m .
The data also show that no State or Federal ambient S02
standards were violated. Sampling for SO2 emissions was con-
ducted in 22 separate periods at 19 locations at distances rang-
ing from about 1 to 10 kilometers from the plant. The highest
average concentration measured was 80.6 yg/m , registered about 3
kilometers downwind of the plant.
Figure 4-14 shows the sampling sites. Table 4-74 summarizes
State and Federal ambient air regulations and maximum recorded
values for the Fox Lake plant.
4.8.4 Plant Programs for Complying with Emission Regulations
Fox Lake is in compliance with the S02 emission regulation
when firing low-sulfur coal, but cannot meet the particulate
emission regulation. The plant had a "Stipulation Agreement"
with the State of Minnesota allowing unlimited particulate emis-
sions until an electrostatic precipitator (ESP) could be retro-
fitted or until July 1, 1977. An ESP with a design efficiency of
99.0 percent is on order from Buell Engineering. This will allow
the plant to comply with the particulate regulation.
4.8.5 Analysis of Coal Conversion Potential
2
Coal Availability —
The coal burned at the Fox Lake plant is purchased under a
long-term contract with Westmoreland Resources and supplied by
Sierra Research Corporation. Air Quality Impact Analysis.
Final Report. June 6, 1973.
2
Foster Associates, Inc. Present and Prospective Coal Supply to
the Fox Lake Plant - Interstate Power Company. May 24, 1976.
FOX LAKE POWER PLANT 4-108
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BIG TWIN
LAKE
Figure 4-14. Ambient sampling locations in the vicinity
of the Fox Lake power plant.
FOX LAKE POWER PLANT
4-109
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TABLE 4-74. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
WITH MAXIMUM RECORDED VALUES NEAR THE FOX LAKE POWER PLANT
(Concentration in ug/m )
Pollutant
Participates
Annual geometric
mean
24-hour maximum
SO2
Annual arithmetic
mean
2 4 -hour maximum
3-hour maximum
Ambient Air Quality Standards
Federal
Primary
75
260
80
365
Secondary
60
150
1300
State
Primary
75
260
60
260
655
Secondary
60
150
60
260
655
Maximum
recorded
values
40.2
80.6
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their mines in Big Horn County, Montana. Westmoreland Resources
indicates that considerable surplus production will be available
through 1980. Because of these contractual commitments and the
availability of additional coal with the necessary sulfur con-
tent, no other sources of supply are evaluated. Table 4-75
presents a typical coal analysis of the Montana coal.
TABLE 4-75. ANALYSIS OF AVAILABLE COAL FOR THE FOX LAKE PLANT
Analysis
Heating value
Sulfur
Ash
Montana coal,
Producing District 22
8450 - 8650 Btu/lb
0.7 - 0.8%
8.0 - 11.0%
The Fox Lake plant is located on the Chicago, Milwaukee, St.
Paul of Pacific rail lines. Each of the two railroads now de-
livers 15 cars per week. If the plant is converted to 100 per-
cent coal, the railroad facilities at the plant will be adequate.
Coal from Westmoreland Resources originates on the Burlington
Northern in Big Horn County, Montana (Producing District 22).
The coal is transferred to the Chicago, Milwaukee, St. Paul &
Pacific Railroad at St. Paul, Minnesota, for delivery to the
plant at Sherburn, Minnesota. The Burlington Northern indicates
that hopper car capacity is readily available to transport the
additional required coal. Table 4-76 shows estimated delivered
coal costs.
FOX LAKE POWER PLANT 4-111
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TABLE 4-76. ESTIMATED DELIVERED COAL COSTS
FOR THE FOX LAKE PLANT
Price (f .o.b. mine) , $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/10 Btu
Montana coal ,
District
5.21
19.28
24.49
1.4l7a
1.562a'd
Producing
22
8.75
19.28
28.03
1.639b
1.806b'd
8.38
19.28
27.66
1.618C
1.783C'd
Cost under existing long-term contract at 8640 Btu/lb.
Cost under new long-term contract at 8550 Btu/lb.
Cost for present average spot-purchase price at 8550 Btu/lb.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Conversion—
Although Boiler 3 is currently firing coal, a 65 percent
derating will occur during 100 percent coal firing. To provide
full capacity during total coal firing, additional coal handling
and fuel firing equipment must be added. The following list of
major equipment and associated costs, was developed by plant
officials in 1975.
Bunkers
Feeders
Pulverizers
Burners
Piping
Soot blowers
Controls
300,000
50,000
900,000
25,000
100,000
75,000
50,000
Total
$1,500,000
PEDCo estimates a coal conversion cost of $2,162,000; this
amount includes Interstate Power Company's estimate escalated to
1978 dollars plus $430,000 for wastewater treatment. Interstate
FOX LAKE POWER PLANT
4-112
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Power estimates the differential operating and maintenance costs
(difference in cost of firing mixed fuel and total coal) to be
0.5 mills/kWh. To attain 86 MW when firing coal, necessary
outage time is estimated to be 1 month and leadtime, 18 months.
Coal conversion data are presented in Table 4-77.
4.8.6 Analysis of Methods for Controlling S02 Emissions
Low-sulfur Coal—
The Fox Lake plant is now in compliance with the Minnesota
S0? emission regulation while firing coal from Big Horn County,
Montana. Since the plant has a long-term contract for this
complying-sulfur coal, flue gas desulfurization systems are not
evaluated.
4.8.7 Analysis of Methods for Controlling Particulate Emissions
Boiler 3 has no control equipment, and particulate emissions
are not in compliance during coal firing. The ESP on order from
Buell Engineering should bring the boiler into compliance. The
ESP will have a plate area of 93,312 sguare feet and a design
efficiency of 99.0 percent, based on firing low-sulfur coal.
The plant reports the capital cost of the ESP to be $3,500,000
($40.70/kW). Based on current fuel costs, PEDCo estimates the
annual fuel cost resulting from conversion from oil to coal to be
$1,382,000 (4.83 mills/kWh).
4.8.8 Recommended Coal Conversion/Compliance Strategy
Considering the available options for converting the plant
to coal firing, the recommended strategy is to continue firing
complying-sulfur coal in Boiler 3 to remain in compliance with
SO- emission regulation and to control particulate emissions with
a new ESP (on order). Estimated emission rates and applicable
regulations using the recommended strategy are shown in Table
4-78.
FOX LAKE POWER PLANT 4-113
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TABLE 4-77. COAL CONVERSION DATA FOR THE FOX LAKE POWER PLANT
Boiler
No.
3
Total
Capacity
factor
(1975) ,
38.0
Fuel consumption
Type
Coal
Gas
Quantity /yr
6934 ton
1985 MM ft3
Coal conversion data
Conv. cost,
2,162,000°
b
Coal usage,
tons/yr
118,000
118,000
a 1975 consumption data from Power Plant Survey Form (Appendix H).
b Based on direct Btu conversion from gas to coal; additional coal required
for total coal firing.
c Total reported by plant; breakdown given in technical factors section.
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TABLE 4-78. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE FOX LAKE POWER PLANT
fuel type
BOILER 3
Alternate fuel
Coala
Sulfur dioxide
Actual
emission rate
lb/106 Btu
1.64 .
<1.64)b
tons/yr
1726
(1726)b
Al lowable
emission rates
lb/106 Btu
4.0
tons/yrb
4210
Particulate
Actual
emission rate
lb/106 Btu
0.09
(9.14)b
tons/yr
96 h
<9616>D
Allowable
emission rates
lb/106 Btu
0.6
tons/yrb
640
a Emissions based on coal analysis of 0.73% sulfur, 9.09% ash, 8450 Btu/lb and ESP with a design efficiency of 99.0%.
Numbers in parentheses represent potential emission resulting from total coal conversion without the installation of
additional control equipment.
Based on estimated coal consumption as shown in Table 4-77.
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4.9 HUDSON PLANT
4.9.1 Plant Description
The Hudson power plant, owned and operated by Public Service
Electric and Gas Company (PSE&G), is located on the east bank of
the Hackensack River, in Jersey City, New Jersey. This area is
part of the New Jersey-New York-Connecticut Interstate Air Qual-
ity Control Region (AQCR 043).
The Hudson plant has two boilers; together they have a total
continuous generating capacity of 983 MW. Boiler 1 is a 383-MW
cyclone-fired, wet-bottom unit built by Babcock & Wilcox. It was
designed to fire coal and residual oil. Boiler 2 is a 600-MW
pulverized-coal-fired, dry-bottom unit manufactured by Foster
Wheeler Corporation. The boilers exhaust through individual 326-
and 498-ft stacks. The electrostatic precipitators (ESP's) on
Boilers 1 and 2 have design particulate removal efficiencies of
99 and 99.5 percent. Only Boiler 1 is being evaluated for coal
conversion.
Table 4-79 presents additional design and operating data on
the two boilers, and Figure 4-15 shows a site plan of the plant.
4.9.2 Fuel Supply and Characteristics
In 1975, Boiler 1 fired 3,074,000 barrels of residual oil
and 865 million cubic feet of natural gas. The Hudson plant
purchased the residual oil from Amerada Hess on a contract basis.
Natural gas was obtained from various suppliers on an interrupt-
ible basis. Tables 4-80 and 4-81 present the latest available
fuel analyses and fuel costs.
HUDSON POWER PLANT 4-116
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TABLE 4-79. DESIGN AND OPERATING DATA ON THE
HUDSON POWER PLANT BOILERS
C
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£
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Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input,0 106 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
Coal firing
1
383
7217
55. 3
1
B&W
1964
124
3581
326
1,032,000
291
ESP
2
600
4027
28.1
2
PW
1968
197
5520
498
1,800,000
279
ESP
a Information from Power Plant Survey Form (Appendix I).
B&W - Babcock & Wilcox; FW - Foster Wheeler.
c Based on coal heat rate of 9350 and 9200 Btu/kWh, respectively,
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COAL CONVEYING
SYSTEM /
^
<$/ DISCHARGE
^fV-^SL-^
HACKENSACK RIVER
I
\->
H-
00
Figure 4-15. Site plan of the Hudson power plant.
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TABLE 4-80. ANALYSES OF CURRENT FUEL
AT THE HUDSON POWER PLANT
Analysis
Heating Value
Sulfur
No. 6 fuel oil
142, 810 Btu/gal
0.3%
Natural gas
1030 Btu/ft"5
Information from Power Plant Survey Form (Appendix I)
TABLE 4-81. COSTS OF FUEL AT THE HUDSON POWER PLANT
Type of purchase
Contract
Interruptible
No. 6 fuel oil
2.234
Natural gas
2.052
a Information from Electrical Week magazine, July 24, 1978.
4.9.3 Atmospheric Emissions
The Environmental Protection Agency (EPA) has classified
AQCR 043 as Priority I with respect to emissions of particulates
and sulfur oxides.
The New Jersey Administrative Code (N.J.A.C.) Regulations
7:27-3.2 and 7:27-4.2 limit particulate emissions to 0.10 lb/10
Btu heat input per stack and opacity to a maximum of 20 percent.
Regulation N.J.A.C. 7:27-10.3(b) classifies Boiler 1 as an exist-
ing reconstructed source when firing coal. Regulations N.J.A.C.
7:27-10.2(d) and (e)-l limit the sulfur content of coal to 0.20
percent by weight or 0.30 lb/10 Btu heat input per stack when a
scrubbing system is in operation. Regulation N.J.A.C. 7:27-9.2
limits the sulfur content of residual oil to 0.3 percent by
weight.
HUDSON POWER PLANT
4-119
-------
Table 4-82 summarizes emission rates and applicable regula-
tions for the Hudson power plant when burning residual oil and
natural gas.
Air Quality Monitoring Data—
No ambient particulate or ambient sulfur dioxide (SO^)
monitoring data are currently available.
4.9.4 Plant Programs for Complying with Emission Regulations
The Hudson plant is in compliance with SO- and particulate
emission regulations when firing residual oil and natural gas.
Coal firing under the present conditions, however, would produce
unacceptable levels of SO- and particulate emissions. The of-
ficials of PSE&G have evaluated the costs of a magnesium oxide
SO- scrubbing system in the event Boiler 1 is converted to 100
percent coal firing; however, no compliance plans have been
formulated.
4.9.5. Analysis of Coal Conversion Potential
Coal Availability --
Boiler 1 at the Hudson plant is a cyclone-fired unit that
requires coal with an ash fusion temperature of no higher than
2300°F. Such a coal is available from central Pennsylvania
(Producing District 1) and northern West Virginia (Producing
District 3).
Coal mined in central Pennsylvania would be transported on
the Consolidated Rail Corporation (ConRail) lines to Port Reading,
New Jersey. From there it would be shipped to the Hudson plant
by barge. No major problems are foreseen in obtaining hopper
cars or barges for transport of the coal.
Table 4-83 presents a typical analysis of coal from Produc-
ing District 1, and Table 4-84 presents the estimated cost of
delivered coal.
Foster Associates, Inc. Present and Prospective Coal Supply
to the Hudson Plant - Public Service Electric and Gas Company
September 9, 1976.
HUDSON POWER PLANT 4-120
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TABLE 4-82. EMISSION RATES AND APPLICABLE REGULATIONS
FOR CURRENT FUEL USAGE AT THE HUDSON POWER PLANT
2
•-3
Fuel type
BOILER 1
Current fuela
Oil
Gas
Sulfur dioxide
Actual
emission rate
lb/106 Btu
0. 33
0.0006
tons/Yr
3041
4
Allowable
emission rate
lb/106 Btu
0.33
0. 3
tons/yr
3041
134
Part iculate
Actual
emission rate
lb/106 Btu
0.06
0.015
tona/yr
T
Allowable
emission rate
lb/106 Btu
0.1
0.1
tons/yr
922
46
Based on 1975 consumption, AP-42 emission factors, a gas analysis of 1030 Btu/ft3, and an oil analysis of 0.3 percent
sulfur and 142,810 Btu/gal.
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TABLE 4-83. ANALYSIS OF COAL AVAILABLE TO THE
HUDSON POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Central Pennsylvania
12,500
2.0
15.0
TABLE 4-84. ESTIMATED COST OF COAL FOR THE
HUDSON POWER PLANT
Price, f.o.b. mine, $/ton
Transporation cost, $/ton
Rail
Barge
Total cost, $/ton
Total cost, $/10 Btu
1978 total cost, $/106 Btu
Central Pennsylvania
19.00
6.91
1.00
26.91
1.076'
1.186
a,b
Based on a heating value of 12,500 Btu/lb.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Fuel Conversion—
Because Boilers 1 and 2 are designed to fire coals with
different ash fusion temperatures, separate coal piles would be
required. The coal storage area adjacent to the plant is limited,
however, and alternative facilities may be required for storage.
Coal handling equipment, ash handling equipment, and the like are
still in place but would require extensive overhauling to be made
HUDSON POWER PLANT
4-122
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operational. If Boiler 1 is converted to coal firing and usage
of residual oil is curtailed, the plant will have to pay a pipe-
line penalty of $3,601,000. For these reasons, PSE&G officials
have estimated total conversion cost to be $15,080,000 (1978
dollars). This cost was derived from a letter from Mr. James
Shissias of Public Service Electric and Gas Company to Mr. Richard
Atherton of the U.S. Environmental Protection Agency, dated April
20, 1977, and escalated to 1978 dollars. Coal conversion data
are presented in Table 4-85.
4.9.6 Analysis of Methods for Controlling SO,, Emissions
Low-sulfur Coal—
No available coal can be guaranteed to meet the New Jersey
standard of 0.2 percent sulfur content.
Flue Gas Desulfurization (FGD)—
The limestone scrubbing and sodium solution regenerable
systems, evaluated for control of SO- emissions from Boiler 1,
are based on SO- removal efficiencies of approximately 90 per-
cent. This efficiency would enable the plant to meet the New
Jersey emission regulation of 12,500 Btu/lb when firing 2.0
percent sulfur coal.
The capital cost of retrofitting Boiler 1 with a limestone
scrubbing system, including a coal conversion cost of $15,080,000,
is estimated to be $52,177,000 ($136.23/kW). Annual operating
costs, including a fuel credit (in switching from oil/gas firing
to coal firing), is estimated to be $2,420,000 (1.72 mills/kWh).
The capital cost of a sodium solution regenerable system,
including coal conversion cost, is estimated to be $61,714,000
($161.13/kW). Annual operating costs are estimated to be
$1,079,000 (0.77 mills/kWh); this figure includes a fuel credit.
HUDSON POWER PLANT 4-123
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TABLE 4-85. COAL CONVERSION DATA FOR THE HUDSON POWER PLANT
Boiler
No.
1
2
Total
Capacity
factor
(projected) ,
%
42.0
Fuel consumption3
Type
Oil
Gas
Coal
Gas
Quantity/yr
3,074,200 bbl
865 106 ft3
529,000 ton
2,490.2 106 ft3
Coal conversion data
Conv. cost,
$
15,030,000
NA
15,080,000°
Coal usage,
tons/yr
527,000
NA
527,000
Information from Power Plant Survey Form (Appendix I).
Additional coal required for conversion of Boiler 1 to 100 percent coal firing,
based on a heat rate of 9350 Btu/kWh and the projected capacity factor.
c Based on Public Service Electric and Gas Company's letter to EPA, dated April
20, 1977; and escalated to January 1978 dollars.
NA - Not applicable.
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4.9.7 Analysis of Methods for Controlling Particulate Emissions
Boiler 1 is equipped with a Western Precipitation Company
ESP with, a design efficiency of 99 percent and a total plate area
of 191,808 square feet. Based on the firing of central Pennsyl-
vania coal and on the age of the ESP, the estimated effective
efficiency of this equipment is 86 percent, which would not
enable Boiler 1 to be in compliance with the particulate emission
regulation.
Compliance with the particulate emission regulation can be
accomplished by installing an add-on ESP with a particulate
removal efficiency of approximately 41.5 percent and a plate area
of 253,700 square feet. The capital cost of installing such an
add-on ESP is estimated to be $24,772,000 ($64.68/kW); this
includes a coal conversion cost of $15,080,000. Annual operating
costs are offset by a fuel credit, resulting in a net annual
credit of $7,480,000 (5.31 mills/kWh). To operate with this
control option, PSE&G must obtain an SO- emission variance from
the State of New Jersey.
Compliance with the particulate emission regulation can also
be accomplished by installing venturi scrubbers in conjunction
with an FGD system and firing 2.0 percent sulfur coal. Venturi
scrubbers are included in the FGD cost evaluations.
4.9.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting Hudson Boiler 1 to
coal firing, the recommended strategy is to fire coal from central
Pennsylvania and to install a sodium solution regenerable system
with venturi scrubbers as a means of complying with both SO- and
particulate emission regulations.
Table 4-86 presents an assessment of the costs of the recom-
mended strategy and other emission control options. Table 4-87
presents emission rates and applicable regulations for Boiler 1,
based on the recommended strategy.
HUDSON POWER PLANT 4-125
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TABLE 4-86. ASSESSMENT FOR EMISSION CONTROL COSTS
AT THE HUDSON POWER PLANT - 1978
Emission control alternative
Combined SO2/particulate
control
Low-sulfur coal
a
Limestone scrubbing
Sodium solution regenerable
Particulate control
Electrostatic precipitator
installation"
Flue gas conditioning
Time
rct]U i rt_-d ,
mon t hs
NA
36
36
36
NA
C-J(M tal
$ 106
52.18
61.71
24.77
a,b
cost
SAW
136.23
161.13
64 .68
a
Annual! zed cost
Kucl .
mi lls/kWh
(10.62)
(10.62)
(10.62)
O&M,C
mills/ki-.'h
6.85
4.49
3.96
Fixed ,
nu lls/kWh
5.49
6.90
1.35
To t a 1 .
mil Is/kWh
1.72
0.77
(5.31)
S 106
2.42
1.08
(7.48)
a costs are in January 1978 dollars; they have not been escalated through project completion and do not include
replacement power.
b Costs include a coal conversion cost of 515,080,000, an anount given to EPA in a letter from PSE&G and
escalated to January 1978 dollars.
c Costs include additional operating and maintenance costs of $1,817,000 (submitted by PSE&G) escalated to
January 1978 dollars.
d Systems are based on a coal analysis of 2.0 percent sulfur, 15 percent ash, and 12,500 Btu/lb. Numbers in
parentheses indicate credits.
NA - Not applicable.
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TABLE 4-87. EMISSION RATES AND REGULATIONS IF THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY IS APPLIED AT THE HUDSON POWER PLANT
Fuel type
Boiler 1
Alternate fuel
Coal
Sulfur dioxide
Actual
emission rate
lb/106 Btu
0,3
(3.04)
tons/yr
1976
(20,027)
Allowable
emission rate
lb/106 Btu
0.3
tons/yr
1976
Particulate
Actual
emission rate*5
lb/106 Btu
0.1
(0.17)
tona/yr
659
(1104)
Allowable
emission rate
lb/106 Btu
0.1
tons/yr
659
Based on heat rate, AP-42 emission factors and a coal analysis of 15.0 percent ash, 2.0 percent sulfur,
and 12,500 Btu/lb. Numbers in parentheses indicated potential emissions resulting from a total conver-
sion to coal firing without the installation of additional control equipment.
to
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4.10 JONES STREET PLANT
4.10.1 Plant Description
The Jones Street power plant (owned and operated by Omaha
Public Power District) is located on the west bank of the Mis-
souri River, approximately 1 mile east of the business district
of Omaha, Nebraska. This area is part of the Metropolitan Omaha
Council Bluffs Air Quality Control Region (AQCR 085).
The two boilers at the Jones Street plant are being evalu-
ated for conversion to coal firing. Boilers 26 and 27 began
operation in 1949 and 1951, respectively, and have maximum con-
tinuous generating capacities of 36 and 47 MW. Originally both
boilers were designed to fire natural gas and coal, but in 1972
they were converted to fire No. 2 fuel oil and natural gas. Each
boiler is equipped with a mechanical collector that has a design
efficiency of 85 percent. The boilers, which were built by
Babcock and Wilcox, exhaust through a common 147-ft stack.
Additional boiler design and operating data are presented in
Table 4-88; a site plan of the plant is shown in Figure 4-16.
4.10.2 Fuel Supply and Characteristics
In 1975, the Jones Street boilers fired natural gas and No.
2 fuel oil. The two boilers consumed a total of 17,377 bbl of
No. 2 fuel oil and approximately 561 million ft of natural gas.
The Jones Street plant obtains No. 2 fuel oil from the Mobil,
Milder, and Sun companies. The latest available fuel analyses
and fuel costs are presented in Tables 4-89 and 4-90, respec-
tively.
JONES STREET POWER PLANT 4-128
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TABLE 4-88. DESIGN AND OPERATING DATA FOR THE JONES STREET POWER PLANT
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975)
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input, 106 Btu/hc
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
Coal firing3
26
36
1,460
7.1
26/27
B&W
1949
22.1
459
147
442,238
320
Mechanical
collector
27
47
1,224
9.1
26/27
B&W
1951
28.8
599
147
442,238
320
Mechanical
collector
NJ
VO
Information from Power Plant Survey Form (Appendix J).
B&W - Babcock and Wilcox.
Based on a heat rate of 12,750 Btu/kWh and a heat value of 10,400 Btu/lb.
The flow rate of 442,238 acfm represents the total flow from Boilers 26 and
27 as it passes through the split stack.
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W
W
/
WARE-
HOUSE
O O
GAS
TURBINES
GUARD
J^HOUSE
O X
I— r K x H x x
I EQUIP. /
STORAGE^/
Ul
O
Figure 4-16. Site plan of Jones Street power plant,
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TABLE 4-89. ANALYSES OF FUEL BURNED AT THE
JONES STREET POWER PLANT
Analysis
Heating value
Sulfur
Fuel oil
137,698 Btu/gal
0.25%
Natural gas
1,000 Btu/ft3
Information from Power Plant Survey Form (Appendix J).
TABLE 4-90. COSTS OF FUEL AT THE JONES STREET POWER PLANT
Fuel cost, $/10 Btu
Type of purchase
Contract
Interruptible
Fuel oil
2.078b
Natural gas
1.084a
Information from Federal Power Commission (FPC) Form 423,
February 1976 and escalated to 1978 dollars.
Information from Electrical Week magazine, January 1978.
4.10.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 085
as Priority I with respect to particulate emissions, and Priority
II with respect to sulfur oxide emissions.
Rule 6b of the Nebraska Air Pollution Control Rules and
Regulations states that the maximum particulate emission allowed
is 0.2 lb/10 Btu heat input. Rule 9 of the regulation states
that the maximum sulfur dioxide emission allowed is 2.5 lb/10
Btu heat input.
Table 4-91 presents emission rates and regulations appli-
cable to the Jones Street power plant.
Air Quality Monitoring Data—
No ambient particulate or ambient SO monitoring data are
currently available.
JONES STREET POWER PLANT
4-131
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TABLE 4-91.
EMISSION RATES AND REGULATIONS USING CURRENT FUELS
AT THE JONES STREET POWER PLANT
Fuel type
BOILER 26
Current fuel
Oil3
Gasb
BOILER 27
Current fuel
Oil3
Gasb
Sulfur dioxide
Actual
emission rate
lb/10G Btu
0.29
0.0006
0.29
0.0006
tons/yr
7.0
< 1
7.4
< 1
Allowable
emission rates
lb/106 Btu
2.5
2.5
2.5
2.5
tons/yr
61
341
65
360
Particulate
Actual
emission rate
lb/10G Btu
0.06
0.015
0.06
0.015
tons/yr
1.4
2.0
1.5
2.2
Allowable
emission rates
lb/106 Btu
0.2
0.2
0.2
0.2
tons/yr
4.9
27.3
5.2
28.8
Emissions based on 1975 oil consumption; an on anaiy**.* ^-- -.«.-. — .-. --
Emissions based on 1975 gas consumption, a gas analysis of 1,000 Btu/ft', and emission factors.
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4.10.4 Plant Programs for Complying with Emission Regulations
The Jones Street plant is in compliance with the Nebraska
emission regulations when firing residual oil and/or natural gas,
If Boilers 26 and 27 are converted to 100 percent coal firing,
the plant (under present conditions) would not meet the particu-
late emission regulation. Omaha Public Power District has not
formulated compliance plans for the Jones Street power plant in
the event it is ordered to convert to coal.
4.10.5 Analysis of Coal Conversion Potential
Coal Availability —
The Omaha Public Power District Company purchases coal on a
spot basis from Arch Mineral Corporation in Carbon County,
Wyoming (Producing District 19). The Arch Mineral Corporation
probably could supply the Jones Street plant with a low-sulfur
2
coal that would meet Nebraska's SO- emission regulation.
Typical characteristics of coal obtained from Carbon County are
presented in Table 4-92.
TABLE 4-92. ANALYSIS OF COAL AVAILABLE TO THE
JONES STREET POWER PLANT
Analysis
Heating value, Btu/lb
Ash, %
Sulfur, %
Carbon County, Wyoming
10,200 - 10,600
8.0 - 13.0
0.4 - 0.9
The Jones Street plant is located on the Burlington Northern
rail lines. When the plant was converted to oil and gas firing
in 1972, the plant's coal storage area was used for installation
of oil-fired gas turbines and oil storage tanks. The railroad
Foster Associates, Inc. Present and Prospective Coal Supply to
the Jones Street Station - Omaha Public Power District. June
18, 1976.
JONES STREET POWER PLANT
4-133
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facilities at the plant are equipped to handle no more than four
hopper cars per shipment. Coal is received at the North Omaha
Station and stored in the hoppers until required. The hoppers
are used to transfer coal to the Jones Street plant. Facilities
at the Jones Street plant would require upgrading if the plant
were converted to 100 percent coal firing on a continuous basis.
Coal produced near Hanna, Wyoming, is transported on the
Union Pacific Railroad to the North Omaha Station. Officials of
Union Pacific believe that they could transport more than 1
million additional tons of coal per year. In 1975 the railroad
installed 1069 new and rebuilt hopper cars. In the first quarter
of 1976, an additional 285 hoppers were installed, and 715 hop-
pers were ordered for installation later in the year. Although
some of these hoppers are intended for replacement of old cars
and for commodities other than coal, many will be available for
additional coal traffic.
Table 4-93 presents the delivered cost of the low-sulfur
coal.
TABLE 4-93. ESTIMATED DELIVERED COAL COSTS FOR THE
JONES STREET POWER PLANT
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/106 Btu
Carbon County, Wyoming
14.00
9.17
23.17
1.103£
1.216
a,b
Based on heating value of 10,500 Btu/lb.
Foster Associates values are escalated to 1978
dollars.
JONES STREET POWER PLANT
4-134
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Technical Factors Affecting Fuel Conversion—
The coal storage area has been eliminated by the addition of
four fuel oil tanks and two oil-fired gas turbines. All coal-
conveying and other coal handling equipment have been removed and
disposed of as a result of the conversion to oil and gas firing
in 1972. The cost of coal conversion is estimated to be $3,862,000,
Because of this high cost, there is a strong possibility of the
Jones Street plant being decommissioned if ordered to fire only
coal. Coal conversion data are presented in Table 4-94.
4.10.6 Analysis of Methods for Controlling SO,) Emissions
Low-sulfur Coal—
The Jones Street power plant could fire low-sulfur (0.9% S)
coal from Carbon County, Wyoming, to meet the regulation limiting
sulfur emissions to 2.5 lb/10 Btu heat input. Therefore, flue
gas desulfurization systems (such as the limestone scrubbing and
sodium solution regenerable systems) are not evaluated.
4.10.7 Analysis of Methods for Controlling Particulate
Emissions
Boilers 26 and 27 each have a mechanical collector with a
design efficiency of 85 percent. If the Jones Street plant is
converted to coal firing, the mechanical collectors will not be
able to control the increased amount of particulates to meet
Nebraska's emission limitation. Boilers 26 and 27 are evaluated
for new electrostatic precipitators (ESP's) with design effici-
encies of approximately 97.5 percent each, and total plate areas
of 89,400 and 116,800 square feet, respectively. Capital cost
for installation of the ESP's is estimated to be $10,175,000
($122.59/kW), which includes a coal conversion cost of $3,862,000.
Annual operating cost is estimated to be $1,973,000 (33.09)
mills/kWh), including a fuel cost (in switching from oil/gas
firing to coal firing).
JONES STREET POWER PLANT 4-135
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TABLE 4-94. COAL CONVERSION DATA FOR THE JONES STREET POWER PLANT
Boiler
No.
26
27
Total
Capacity
factor
(1975) ,
%
7.1
9.1
Fuel consumption
Type
Oil
Gas
Oil
Gas
Quantity/yr
8,500 bbl
273,000,000 ft3
8,900 bbl
288,000,000 ft3
Coal conversion data w
Conv. cost,
$
3,862,000°
Coal usage"
tons/yr
14,000
23,000
37,000
*>.
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a 1975 consumption figures from Power Plant Survey Form (Appendix J).
b Based on capacity factors, heat rate of 12,750 Btu/kWh, and heat value of
10,400 Btu/lb.
c Cost reported by Omaha Public Power District in 1975, escalated to 1978
dollars. This cost also includes a new stack estimated by PEDCo at
$558,000.
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4.10.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the Jones Street
plant to coal firing, the recommended strategy is to fire low-
sulfur coal from Wyoming and to install new ESP's on Boiler's 26
and 27 to comply with applicable SCu and particulate emission
regulations. Table 4-95 presents the cost assessment for the
ESP's. Table 4-96 presents emission rates and regulations for
the Jones Street plant based on the recommended strategy.
JONES STREET POWER PLANT 4-137
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TABLE 4-95. COST ASSESSMENT FOR EMISSION CONTROLS AT THE
JONES STREET POWER PLANT - 1978
Emission control
alternative
Combined SO2/particulate
controls
Limestone scrubbing
Sodium solution
regenerable
Particulate control
Electrostatic precip-
itator installation
i c.d
Low-sulfur coal
Flue gas conditioning
Time
requ i red ,
months
NA
NA
36
NA
Capital
$ 106
10.18
a
cost
S/kW
122.59
Annualized cost
Fuel,
mills/kWh
2.14
O&M,
mills/kWh
9.58
Fixed ,
mills/kWh
21.37
Total.
mills/kWh
33.09
S 10*>
1.97
a Includes coal conversion cost of $3,862,000-
b Includes additional annual cost of $100,000 for coal handling as reported by plant.
c ESP design for Boilers 26 and 27 is for coal with an analysis of 0.9* S, 10.00% ash, and 10,400 Btu/lb.
d Costs are in January 1978 dollars; they have not been escalated through project completion and do not in-
clude replacement power.
NA - Not applicable.
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TABLE 4-96. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE JONES STREET POWER PLANT '
Fuel type
DOILER 26
Alternate fuel
Coala
BOILER 27
Alternate fuel
Coal3
Sulfur dioxide
Actual
emission rate
lb/106 Bti
1.6
(1.6)
1.6
(1.6)
tons/yr
235
235
393
393
Allowable
emission rate
lb/106 Btu
2.5
2.5
tons/yr
357
597
Particulate
Actual
emission rate
lb/106 Btu
0.2
(8.2)
0.2
(8.2)
tons/yr
29
(1167)
48
(1952)
Allowable
emission rate
lb/106 Btu
0.2
0.2
tons/yr
29
48
Based on 1975 operating data, a boiler heat rate of 12,750 Btu/kWh, and a coal analysis of 0.9% sulfur,
10% ash, and 10,400 Btu/lb. Numbers in parenthesis indicate potential emissions resulting from a total
conversion to coal firing without the installation of additional control equipment.
U)
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4.11 LAKE ROAD PLANT
4.11.1 Plant Description
The Lake Road plant (owned and operated by St. Joseph Light
& Power Company) is located on the east shore of the Missouri
River in St. Joseph, Missouri, which is part of the Metropolitan
Kansas City Interstate Air Quality Control Region (AQCR 094).
Lake Road has seven boilers. Boilers 1 through 7 were
placed in operation in 1961, 1961, 1938, 1950, 1957, 1967, and
1974, respectively. Boilers 1 and 2 are Combustion Engineering
units rated at 11 MW each. Boilers 3 through 6 are Babcock &
Wilcox units rated at 16.5, 23, 27.5, and 103 MW, respectively.
Boiler 7 is a Westinghouse combined-cycle unit rated at 78.5 MW.
Boilers 1, 2, and 3, which can fire natural gas and oil, are
served by individual 92-ft stacks. Boilers 4 and 5, pulverized-
coal-fired boilers capable of firing coal, oil, and natural gas,
are served by individual 150-ft stacks. Boiler 6, a cyclone
boiler capable of firing coal and natural gas, is served by a
225-ft stack. Boiler 7, which is designed to fire oil and natu-
ral gas, is served by a 52-ft stack. Boiler 4 is equipped with a
multicyclone mechanical collector. Boilers 5 and 6 are equipped
with electrostatic precipitators (ESP's).
Table 4-97 presents additional design and operating data on
Boilers 5 and 6, the only two Lake Road boilers being evaluated
for coal conversion. Figure 4-17 shows a site plan of the entire
plant.
4.11.2 Fuel Supply And Characteristics
Boilers 5 and 6 at the Lake Road plant fired mostly coal and
natural gas in 1975 (1.495 billion cubic feet of natural gas,
2805 barrels of residual oil, and 102,363 tons of coal). Because
Boiler 6 was inoperative for much of 1975 (18.5% capacity fac-
tor) , fuel data for 1974 are used in PEDCo's evaluation. Average
yearly fuel consumption (based on 1975 data for Boiler 5 and 1974
LAKE ROAD POWER PLANT 4-140
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TABLE 4-97. DESIGN AND OPERATING DATA FOR THE LAKE ROAD POWER PLANT
tr1
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Item
Boiler number
Generating capacity, MW
Hours of operation
Average capacity factor, %
Served by Stack No.
Boiler manufacturer0
Year placed in service
Max. coal consumption, tons/h
Max. heat input, 106 Btu/hd
Stack height, ft above grade
Flue gas rate maximum, acfm
Flue gas temperature, °F
Emission controls
Coal
5
27.5
7767
63.6
5
B&W
1957
15.9
371
150
129,400
314
ESP
firing3
6
103
8017
70.1
6
B&W
1967
44.6
1146
225
323,800
365
ESP
Information from Power Plant Survey Form (Appendix K).
Based on 1975 data for Boiler 5 and 1974 data for Boiler 6.
B&W - Babcock & Wilcox Company.
Based on rates of 13,500 and 11,300 Btu/kWh for Boilers 5 and 6,
respectively.
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1. CENTRAL PLANT COMPLEX
2. ROTARY CAR UNLOADER AND TRACK HOPPER
3. ACTIVE STORAGE RECLAIM STRUCTURE
4. CRUSHER HOUSE
5. RESERVE STORAGE PILE
6. ACTIVE STORAGE PILE
7. TEMPORARY STORAGE PILE
8. STOCKOUT CONVEYOR
9. RECLAIM CONVEYOR
10. ASH STORAGE PONDS
11. HOLDING BASIN
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
1 BOILER STACK
2 BOILER STACK
3 BOILER STACK
4 BOILER STACK
5 BOILER STACK
6 BOILER STACK
S.G. STACK
BYPASS STACK
NO. 3 OIL TANK
NO. 1 OIL TANK
NO. 4 OIL TANK
NO.
NO.
NO.
NO.
NO.
NO.
H.R,
MISSOURI RIVER
10
Figure 4-17. Site plan of the Lake Road power plant.
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data for Boiler 6) is 6.366 billion cubic feet of natural gas,
2805 barrels of residual oil, and 120,540 tons of coal. Lake
Road receives its fuel oil from the E. L. Bride Company. Coal is
obtained from Missouri Mining, Inc., in Putnam County, Missouri,
and from Kansas. Tables 4-98 and 4-99 present the latest avail-
able fuel analyses and fuel costs.
4.11.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 094
as Priority I with respect to particulate emissions and Priority
III with respect to sulfur oxide emissions.
Regulation III of the Air Quality Standards and Air Pollu-
tion Control Regulations of the Kansas City Metropolitan Area
limits particulate emissions to 0.16 lb/10 Btu, based on the
total heat input of the plant. Missouri has no SCu emission
limitations, but it does have an air quality standard. Ambient
air concentrations of sulfur oxides (SO ) are not to exceed the
J\.
following:
Concentrations
0.25
0.07
Averaging
time
1-hour
24-hour
Maximum allowable
frequency
Once in any 4 days at
any sampling site
Once in any 90 days at
any sampling site
Table 4-100 summarizes emission rates and regulations for fuel
currently fired at the Lake Road plant.
Air Quality Monitoring Data--
No ambient particulate or SO- monitoring data are available
for the Lake Road power plant. The applicable State and Federal
ambient air standards for the plant are summarized in Table 4-101
LAKE ROAD POWER PLANT
4-143
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TABLE 4-98. ANALYSES OF FUEL USED AT THE
LAKE ROAD POWER PLANT
Analysis
Heating value
Sulfur
Coala
10,050 Btu/lb
3.8%
12,000 Btu/lb
3.5%
Oil3
148,074 Btu/gal
;a
Natural gas
962 Btu/ft3
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Information from Power Plant Survey Form (Appendix K).
TABLE 4-99. COSTS OF FUEL AT THE LAKE ROAD POWER PLANT
Type of purchase
Spot
Spot
Interruptible
Fuel cost,
1.076
2.023b
1.096
$/106 Btu
(coal)
(oil)
(gas)
Information from Electrical Week magazine, April 1978.
Average 1978 oil price for utilities in the Kansas City area
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TABLE 4-100.
EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT
FUEL USAGE AT THE LAKE ROAD POWER PLANT
Fuel type3
BOILER 5
Current fuel
Coal
Oil
Gas
BOILER 6
Current fuel
Coal
Gas
Sulfur dioxide
Actual .
emission rate
lb/106 Btu
7.18
1.80
0.0006
7.18
0.0006
tons/yr
2962
16
<1
5742
1.5
Allowable
emission rates
lb/106 Btu
c
c
tons/yr
c
c
Particulate
Actual b
emission rate
lb/106 Btu
1.84
0.054
0.016
0.454
0.016
tons/yr
758
<1
38
3G3
10
Allowable
emission rates
lb/106 Btu
0.16
0.16
0.16
0.16
0.16
tons/yr
66
1.5
380
32
100
a Fuel analyses are: coal 10,050 Btu/lb, 3.8% sulfur, 15.2% ash; oil 148,074 Btu/gal., 1.7% sulfur; and natural gas
962 Btu/ft3.
b Based on actual fuel usage in 1975 for Boiler 5 and 1974 for Boiler 6 and emission factors from AP-42. Particulate
emissions on coal include mechanical collectors with design efficiencies of 85.7% and 70.0» for Boilers 5 and 6.
c Ambient SO, standards are: 0.25 ppm, 1-h average, once per 4 days; and 0.07 ppm, 24-h average once per 90 days.
. 2 f
Particulate emissions for the entire plant cannot exceed 0.16 lb/10 Btu based on the total plant heat capacity.
Plume opacity cannot exceed 20%, which is more stringent.
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TABLE 4-101. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
APPLICABLE TO THE LAKE ROAD POWER PLANT
(Concentration in ug/m )
Pollutant
Particulates
Annual geometric
mean
24-hour maximum
so2
Annual arithmetic
mean
2 4 -hour maximum
3 -hour maximum
Ambient Air Quality Standards
Federal
Primary
75
260
80
365
Secondary
60
150
1300
State
Primary
60
150
40
159
Secondary
Maximum
recorded
values
NA
NA
NA - Not available.
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4.11.4 Plant Programs for Complying with Emission Regulations
Lake Road is unable to meet the particulate emission regula-
tion when firing coal. The ESP on Boiler 6 became inoperative as
a result of a boiler mishap and was replaced in late 1976. The
company also purchased an ESP for Boiler 5, which was scheduled
into operation in mid-1977. Construction of new coal handling
facilities were begun in 1976 to increase coal utilization capa-
bilities as natural gas service is being curtailed. Compliance
with the ambient SO., emission regulation must be determined by a
modeling study.
4.11.5 Analysis Of Fuel Conversion Potential
Coal Availability —
In the past, St. Joseph Light and Power obtained coal for
the Lake Road plant from Missouri and northern Oklahoma (Produc-
ing District 15) and from western Kentucky (Producing District
9). The present source of coal is Missouri Mining, Inc., in
Putnam County, Missouri. The company is also negotiating a con-
tract with a producer in northern Oklahoma for purchase of 70,000
tons annually. Discussions with producers in these areas indi-
cate surplus capacity is available that could be supplied to the
plant. Low-sulfur coal from the Hanna, Wyoming, area was also
evaluated for blending purposes if the plant is found to be
violating the ambient SO- regulation while burning coal from the
regular supply. Average coal analyses are presented in Table
4-102.
Foster Associates, Inc. Present and Prospective Coal Supply
to the Lake Road Plant - St. Joseph Light and Power Company.
May 24, 1976.
LAKE ROAD POWER PLANT 4-147
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TABLE 4-102. ANALYSES OF AVAILABLE COAL FOR
THE LAKE ROAD POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Northern
Missouri,
Producing
District 15
10,500
2.75
11.0
Northern
Oklahoma,
Producing
District 15
12,750
4.0
12.0
Wyoming,
Producing
District 19
10,300
0.6
The plant is located on the Union Terminal Railway lines in
St. Joseph, Missouri. Shipments of coal produced in northern
Missouri would originate on the Burlington Northern rail lines at
Unionville, Missouri, and be transferred to the Union Terminal
Railway at St. Joseph for final delivery to the plant. Northern
Oklahoma coal would be brought into St. Joseph on the Kansas City
Southern, St. Louis-San Francisco, Missouri-Kansas-Texas, or
Missouri Pacific Railroad. Shipments of Wyoming coal would
originate on the Union Pacific Railroad. Discussions with these
carriers indicate that conditions of roadbeds and availability of
hopper cars present no problem with respect to coal transporta-
tion to the Lake Road plant. Construction of additional coal
handling facilities is under way at the plant, and upgrading of
the rail facilities is expected to be completed in March 1977.
Estimated delivered costs of coal are shown in Table 4-103.
LAKE ROAD POWER PLANT
4-148
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TABLE 4-103. ESTIMATED DELIVERY COAL COSTS
FOR THE LAKE ROAD POWER PLANT
1 Northern
Missouri,
Producing
pistrict 15
Price (f .o.b. mine) ,
$/ton
Transportation cost,
$/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/106 Btu
16.00
4.52
20.52
0.977a
1.076d
Northern
Oklahoma,
Producing
District 15
17.00
7.63
24.63
0.966b
1.065d
Wyoming ,
Producing
District 19
11.25
12.02
23.27
1.130C
1.245d
Based on heating value of 10,500 Btu/lb.
Based on heating value of 12,750 Btu/lb.
Based on heating value of 10,300 Btu/lb.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Conversion--
St. Joseph Light and Power Company is converting Boilers 5
and 6 to total coal firing in preparation for future curtailments
of natural gas. The coal handling facilities now under construc-
tion will cost an estimated $6.5 million. Because these boilers
are being converted as a result of natural gas curtailments
rather than FEA orders, plant officials envision no cost impact
due to a conversion order under the Energy Supply and Environmen-
tal Coordination Act of 1974. Table 4-104 presents additional
coal conversion data.
4.11.6 Analysis of Methods For Controlling SO? Emissions
Low-sulfur Coal—
Compliance with the ambient SO_ regulation when firing 100
percent (Producing District 15) coal must be determined by a
LAKE ROAD POWER PLANT
4-149
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TABLE 4-104. COAL CONVERSION DATA FOR THE LAKE ROAD POWER PLANT
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Boiler
NO.
5
6
Total
Fuel consumption3
Type
Coal
Oil
Gas
Coal
Gas
Quantity/yr
41,018 tons
2,805 bbl
1,284,177 x 103 ft3
79,522 tons
5,081,684 x 103 ft3
Coal conversion data
Conv. cost,
$
NA
Coal usage,
tons/yr"
57,500
261,000
318,500
Based on 1975 operating data for Boiler 5 and 1974 operating- data for
Boiler 6.
Additional coal required if converted to 100% coal firing based on
10,500 Btu/lb coal.
NA - Not applicable.
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modeling study. In the event Boilers 5 and 6 are found to be in
violation, low-sulfur coal from Wyoming (Producing District 19)
can be blended to achieve compliance.
4.11.7 Analysis of Methods for Controlling Particulate Emissions
Boiler 5 is equipped with a multicyclone mechanical collec-
tor manufactured by Western Precipitator Division, which has a
design efficiency of 85.7 percent, an Environmental Elements ESP
with a design efficiency of 99.0 percent, and a plate area of
2
45,900 ft to meet the opacity limits of the Missouri particulate
regulation. The ESP is expected to be on-line by June 1977.
The multicyclone mechanical collector on Boiler 6 is a
Research-Cottrell, Inc., unit with a design efficiency 70.0
percent. An ESP installed on Boiler 6 in 1975 was destroyed in a
boiler mishap, and a new Universal Oil Products ESP was installed
in conjunction with boiler rework. This ESP, designed to meet
the opacity regulation, has a design efficiency of 99.0 percent
and a plate area of 74,520 ft2. These ESP's enable Boilers 5 and
6 to comply with the particulate emission regulation. The plant
reports that the capital cost of the ESP on Boiler 5 was $1,900,000
($69.09/kW), and the cost of the ESP on Boiler 6 was $1,500,000
($14.56/kW). Based on current fuel data, the annual fuel cost
resulting from coal conversion is estimated at $438,000 (0.42
mills/kWh).
4.11.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to coal
firing, the recommended strategy is to continue to burn coal from
its current source until a modeling study can be completed or a
monitoring network can be set up to determine SO- compliance.
Particulate emissions can be controlled with the newly purchased
ESP's. Emission rates and regulations applicable to the recom-
mended strategy are shown in Table 4-105.
LAKE ROAD POWER PLANT 4-151
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TABLE 4-105. EMISSION RATES AND REGULATIONS USING RECOMMENDED
COAL CONVERSION/COMPLIANCE STRATEGY AT THE LAKE ROAD POWER PLANT
Fuel type
BOILER 5
Alternate fuel
Coalb
BOILER 6
Alternate fuel
Coalb
Sulfur dioxide
Actual
emission ratea
lb/106 Btu
i
4.98
(4.98)
4.98
(4 .98)
tons/yr
5147
(5147)
17,765
(17,765)
Allowable
emission rates
lb/106 Btu
c
c
tons/yr
c
c
Particulate
Actual
emission rate3
lb/106 Btu
0.089e
(1.27)
0.011e
(0.314)
tons/yr
92
(1317)
38
(1122)
Allowable
emission rates
lb/106 Btu
0.16
0.16
tons/yr
165
553
3 Based on 10 500 Btu/lb, 2.75* sulfur, 11.0% ash coal and emission factors from AP-42.
b Numbers in parentheses represent potential emissions resulting from a total conversion to coal firing without the
installation of additional control equipment.
c Ambient SO, standards are: 0.25 ppm. 1-h average, once per 4 days; and 0.07 pptn, 24-h average, once per 90 days.
d Particulate emissions for the entire plant cannot exceed 0.16 lb/106 Btu based on the total plant heat capacity.
Plume opacity cannot exceed 20%, which is more stringent.
e Based on ESP's each designed at 99.0% efficiency.
(SI
NJ
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4.12 LOVETT POWER PLANT
4.12.1 Plant Description
The Lovett power plant (owned and operated by the Orange and
Rockland Utilities Company) is located on the Hudson River in
Tomkins Cove, New York. This area is part of the New Jersey/New
York/Connecticut Interstate Air Quality Control Region (AQCR
043) .
Of the five boilers at the Lovett plant, only Boilers 3, 4,
and 5 are evaluated for conversion to coal firing. The five
units have a total maximum continuous generating capacity of
504.8 MW. Boilers 1 through 5 are rated at 19.1, 20, 63, 202.1,
and 200.6 MW, respectively, and were placed in service in 1949,
1951, 1955, 1966, and 1969. The boilers exhaust through indi-
vidual stacks that have respective heights of 175, 175, 175, 212,
and 245 feet. Boilers 1, 2, and 3 are equipped with mechanical
collectors, each with a design efficiency of 85 percent. Boilers
4 and 5 are equipped with electrostatic precipitators (ESP's),
each with a design efficiency of 95 percent. Boilers 1, 2, and 5
were manufactured by Babcock and Wilcox, Boiler 3 by Combustion
Engineering, and Boiler 4 by Foster Wheeler.
Additional boiler design and operating data are presented in
Table 4-106. A site plan of the plant is shown in Figure 4-18.
4.12.2 Fuel Supply and Characteristics
The Lovett plant has been burning natural gas and oil since
the oil embargo in 1974. The residual oil is supplied by Howard
Oil and New England Petroleum Corporations; the gas is supplied
on an interruptible basis. In 1975 Boilers 3, 4, and 5 consumed
2,371,370 bbl of residual oil and 2,925,000 ft3 of gas. Typical
analyses of the current fuels are shown in Table 4-107, and cost
data are presented in Table 4-108.
LOVETT POWER PLANT 4-153
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tr1
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n
1-3
t-3
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TABLE 4-106. DESIGN AND OPERATING DATA FOR THE LOVETT POWER PLANT
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input,0 106 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
Coal firing
3
63
2845
17.2
3
CE
1955
25.0
913
175
252,000
310
Mechanical
collector
4
202.1
6307
36.9
4
FW
1966
60.0
1803
212
648,000
300
ESP
5
200.6
8117
47.7
5
B&W
1969
65.0
1919
245
785,000
288
ESP
I
M
Ln
a Information from Power Plant Survey Form (Appendix L).
b CE - Combustion Engineering; FW - Foster Wheeler; B&W - Babcock & Wilcox,
C Based on boiler heat rates of 13.235, 9.2, and 9.5 x 103 Btu/kWh,
respectively.
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en
en
Figure 4-18. Site plan of the Lovett power plant,
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TABLE 4-107. ANALYSES OF FUEL BURNED AT THE LOVETT POWER PLANT
Analysis
Heating value
Sulfur
Residual fuel oil
144,533 Btu/gal
0.33%
Natural gasa
1,026 Btu/ft3
Information from Power Plant Survey Form (Appendix L).
TABLE 4-108. COSTS OF FUEL AT THE LOVETT POWER PLANT
Fuel cost,3 $/10 Btu
Type of purchase
Contract
Interruptible
Fuel oil
2.132
Natural gas
1.444
Information from Electrical Week magazine, March 1978.
4.12.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 043
as Priority I with respect to emissions of particulates and
sulfur oxides.
The current New York particulate emission regulation limits
emissions to 0.10 lb/10 Btu heat input for all fuels. The
maximum allowable sulfur dioxide (S02) emission from coal firing
is 0.40 lb/10 Btu; the maximum allowable sulfur content of fuel
oil is 0.37 percent.
Table 4-109 summarizes the current emission rates and appli-
cable regulations for the Lovett plant.
LOVETT POWER PLANT
4-156
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-3
•-3
O
5
M
TABLE 4-109.
EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT
FUEL USAGE AT THE LOVETT POWER PLANT
Fuel type
Boiler 3
Current fuel
Oil
Gas
Boiler 4
Current fuel
Oil
Gas
Boiler 5
Current fuel
Oil
Gas
Sulfur d
Actual
emission rate
lb/106 Btu
0.36
0.0006
0.36
0.0006
0.36
0.0006
tons/yr
247
<1
1144
<1
1541
<1
iox idc
Allowable
cm i SG ion ra te
lb/106 Btu
0.4
0.4
0.4
0.4
0.4
0.4
tons/yr
277
14
1285
281
1730
291
Part iculate
Actual
emission rate
lb/106 Btu
0.06
0.015
0.06
0.015
0.06
0.015
tons/yr
38
1
177
11
238
11
Al lowoble
emission rate
lb/106 Btu
0.1
0.1
0.1
0.1
0.1
0.1
tons/yr
69
4
320
70
431
73
a Based on 1975 fuel consumption, AP-42 Emission Factors, a gas analysis of 1026 Btu/ft3, and an oil analysis
of 0.33% sulfur and 144,533 Btu/gal.
(Jl
-J
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Air Quality Monitoring Data —
From June 1974 through May 1975, ambient S02 emissions data
were collected at six monitoring sites (shown in Figure 4-19) ,
all within a 5-mile radius of the Lovett plant. The measurements
show that no New York or Federal ambient S02 air quality stan-
dards were exceeded during the period. No ambient particulate
emissions monitoring data were available.
Table 4-110 summarizes the Federal and State ambient air
quality standards and maximum values recorded near the Lovett
power plant.
4.12.4 Plant Programs for Complying with Emission Regulations
The Lovett power plant operates in compliance with the
State's emission regulations when it fires natural gas and resid-
ual oil. Under present conditions, the plant would violate both
the particulate and sulfur dioxide (S0~) emission regulations if
it were converted to coal firing.
Orange and Rockland has formulated two compliance plans in
the event the Lovett power plant is ordered to fire coal. The
first plan calls for the installation of two additional ESP's to
bring the particulate collection efficiency up to 99 percent. A
tall stack serving Boilers 4 and 5 would also be installed to
provide greater dispersion of sulfur dioxide. For this plan to
meet the emission regulations, the Lovett plant must obtain a
variance on the SG>2 emission regulation. The second plan in-
volves installation of a tall stack and a flue gas desulfuriza-
tion (FGD) system along with the existing ESP's to meet New
York's emission regulations. It is assumed that the FGD system
will be equipped with a venturi scrubber that will be used in
conjunction with the ESP's to enable the plant to comply with the
particulate emission regulation.
Environmental Research and Technology, Inc. Haverstraw, New
York Air Quality Monitoring Program. July 1975.
LOVETT POWER PLANT 4-158
-------
LEGEND
A POWER STATION
O S02 ONLY
®WIND. TEMPERATURE,
RELATIVE HUMIDITY,
AND PRECIPITATION
.STONY POINT
HUDSON RIVER
2.REHABILITATION
HOSP.
L, M, U BOWLINE TOWER
®(/f\
LOVETT
GENERATING
STATION \4.BOWLIN
POINT
6.CROTON POINT
3.LETCHWORTH
VILLAGE
CROTON-ON-
HUOSON
5.HI
Figure 4-19. Sulfur dioxide monitoring sites in the vicinity of the
Lovett power plant.
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O
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tr1
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TABLE 4-110. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
WITH MAXIMUM VALUES RECORDED NEAR THE LOVETT POWER PLANT
(Concentration in ug/m )
Pollutant
Particulate
Annual geometric
mean
Maximum 24-hour
average
Annual arithmetic
mean
Maximum 24-hour
average
Maximum 3-hour
average
Ambient Air Quality Standards
Federal
Primary
75
260
80
365
Secondary
60
150
-
1300
State
Primary
110
80
365
Secondary
75
260
Maximum
recorded
values
NA
NA
40
156
NA
NA - Not available.
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4.12.5 Analysis of Coal Conversion Potential
Coal Availability —
Southern West Virginia and eastern Kentucky (Producing
Districts 7 and 8) are potential sources of coal for the Lovett
plant. Coal produced in these districts generally has a sulfur
content of approximately 1.0 to 1.5 percent.
Coal from southern West Virginia and eastern Kentucky would
be loaded onto the Chessie System and then transferred to ConRail
rail lines at Philadelphia for final delivery to the plant. All
rail lines necessary for this movement are in serviceable condi-
tion, and no transportation problems are anticipated. The
Chessie System has sufficient rolling stock to transport addi-
tional coal. During 1975 the railroad installed 5735 hopper
cars. As of July 1, 1976, an additional 3446 new and rebuilt
hoppers were installed, and 3620 hopper cars were on order for
installation later in 1976.
An average coal analysis is presented in Table 4-111, and
estimated costs of delivered coal are shown in Table 4-112.
TABLE 4-111. ANALYSIS OF COAL AVAILABLE TO THE
LOVETT POWER PLANT
Analysis
Heating value, Btu/lb
Sulfur, %
Ash, %
Eastern
12,000
1.0
10
Kentucky
- 12,500
- 1.5
- 15
2
Foster Associates, Inc. Present and Prospective Coal Supply
to the Lovett Plant - Orange and Rockland Utilities, Inc.
September 9, 1976.
LOVETT POWER PLANT 4-161
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TABLE 4-112. ESTIMATED DELIVERED COAL COSTS FOR
THE LOVETT POWER PLANT
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/10 Btu
6
1978 total cost, $/10 Btu
Eastern Kentucky
18.25
16.71
34.96
1.457
1.606
a
a,b
a Based on a heating value of 12,000 Btu/lb.
b Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Fuel Conversion—
The Orange and Rockland Company believes that no major
equipment changes are required in order for Boilers 3, 4, and 5
to fire coal. Additional land for coal storage and soundproofing
of the car shaker building will be required, however, if the
plant is converted to coal firing. The company estimates the
coal conversion costs to be $3,424,000. Coal conversion data are
presented in Table 4-113.
4.12.6 Analysis of Methods for Controlling S02 Emissions
Low-sulfur Coal--
Coal having a sulfur content of approximately 0.25 percent
and a heating value of 12,000 Btu/lb would be required to meet
the 0.40 Ib SO2/106 Btu regulation. Coal with these character-
istics is not available in commercial volumes.
Flue Gas Desulfurization (FGD)—
A limestone scrubbing and a sodium solution regenerable
system are evaluated for control of S02 emissions from Boilers 3,
4, and 5. These systems are designed to remove 83 percent of the
LOVETT POWER PLANT 4-162
-------
F
O
TABLE 4-113. COAL CONVERSION DATA FOR THE LOVETT POWER PLANT
Boiler
No.
3
4
5
Total
Capacity
factor
(1975) ,
%
17.2
36.9
47.7
Fuel consumption3
Type
Oil
Gas
Oil
Gas
Oil
Gas
Quantity/yr
200,780 bbl
67.9 106 ft3
810,090 bbl
1,402.6 106 ft3
1,360,500 bbl
1,454.8 106 ft3
Coal conversion data
Conv. cost,
$
3,424,000°
Coal usage, b
tons/yr
41,000
243,000
334,000
618,000
13
O
s:
M
Information from Power Plant Survey Form (Appendix L).
Additional coal required for conversion to 100% coal firing based on
heat rates and boiler capacity factors.
Cost is based on Orange and Rockland's estimates; it is escalated to
January 1978 dollars and includes costs that are not applicable to
individual boilers.
CTl
U)
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S0_ emissions, as required to meet the state emission regulation
t- r
of 0.40 Ib S02/10 Btu when 1.5 percent sulfur coal is burned.
Capital cost to install a limestone scrubbing system is
estimated to be $52,202,000 ($112.09/kW), which includes $3,424,000
for coal conversion. Annualized operating cost, including
trucking costs and a fuel credit (in switching from oil/gas to
coal firing), is $9,490,000 (6.01 mills/kWh).
Capital cost of the sodium soltuion regenerable system,
including the coal conversion cost, is estimated to be $57,651,000
($123.79/kW). Annualized cost, including trucking costs and the
fuel credit, is estimated to be $7,012,000 (4.44 mills/kWh).
4.12.7 Analysis of Methods for Controlling Particulate Emissions
Boiler 3 is equipped with a multiple cyclone mechanical
collector that has a design efficiency of 85 percent. Boilers 4
and 5 are each equipped with an ESP that has a design efficiency
of 95 percent. Plate areas of the ESP's for Boilers 4 and 5 are
47,520 and 84,240 square feet, respectively. With this particu-
late control equipment, Boilers 3, 4, and 5 cannot comply with
the particulate emission regulation when firing coal.
Compliance could be accomplished by installing new ESP's on
Boilers 3, 4, and 5 and firing medium-sulfur (1.5% sulfur) coal.
Capital cost for installation of the ESP's is estimated to be
$23,158,000 ($49.73/kW), which includes $3,424,000 for coal
conversion costs. Annual operating costs are offset by the fuel
credit, resulting in a net annual credit of $4,149,000 (2.63
mills/kWh). Costs are based on an ESP efficiency of approxi-
mately 98.7 percent, which is needed to meet the New York partic-
ulate emission regulation of 0.10 lb/10 Btu. Plate areas re-
quired for the ESP's on Boilers 3, 4, and 5 are 113.2, 258.7, and
245.3 thousand square feet, respectively.
LOVETT POWER PLANT 4-164
-------
The plant could also comply with the particulate regulation
when firing coal by installing venturi scrubbers, which would be
used in conjunction with an FGD system. (Costs of Venturis are
included in the FGD evaluations.)
4.12.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the Lovett plant to
coal firing, the recommended strategy is to fire medium-sulfur
(1.5 percent) coal and to install a sodium solution regenerable
system with venturi scrubbers for Boilers 3, 4, and 5 to comply
with applicable SO- and particulate emission regulations.
Cost assessments for the sodium solution regenerable system
and alternative control methods are presented in Table 4-114.
Emission rates and regulations for the recommended strategy for
Boilers 3, 4, and 5 at the Lovett plant are presented in Table
4-115.
LOVETT POWER PLANT 4-165
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F
O
TABLE 4-114. ESTIMATED COSTS OF EMISSION CONTROL OPTIONS
AT THE LOVETT POWER PLANT - 1978
i
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F
>
2
Emission control alternative
SO., control
Low-sulfur coal
Limestone scrubbing0 Blr. 3,4,5
Sodium solution
regenerablec Blr. 3,4,5
Particulate control
Electrostatic precipitator
installation"3 Blr. 3,4,5
Flue gas conditioning
Time
required ,
months
36
36
36
NA
Capital cost
106 $
52.20
57.65
23.16
SAW
Includ
112.09
123.79
49.73
Annual! zed cost
Fuel ,
mills/kuh
ed below in E
(7.11)
(7.11)
(7.11)
O&M,
mills/kKh
:SP calcula
6.68
4.39
2.00
Fixed ,
mills/kWh
:ions
6.44
7.16
2.48
Total,
mi lls/kWh
6.01
4.44
(2.63)
106 S
9.49
7.01
(4.15)
Costs represent January 1978 dollars; they are not escalated through project completion and do not include
replacement power. ESP costs do not include tear-out costs.
Includes coal conversion cost of $3,424,000.
Systems are based on a coal analysis of 1.5% sulfur, 11» dsh, and 12,000 Btu/lb. Numbers in parentheses indicate
credits.
This control option does not meet the SO~ emission regulation.
NA - Not applicable.
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i-3
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£
a
TABLE 4-115.
EMISSION RATES AND REGULATIONS USING THE RECOMMENDED
STRATEGY AT THE LOVETT POWER PLANT
Fuel type
Boiler 3
Alternate fuel
Coal
Boiler 4
Alternate fuel3
Coal
Boiler 5
Alternate fuel
Coal
i Sulfur dioxide
Actual
emi ssion ra te
lb/106 Btu
0.4
(2.38)
0.4
(2.38)
0.4
(2.38)
tons/yr
238
(1411)
1164
(6914)
1604
(9523)
Al lowable
emission rate
lb/106 Btu
0.4
0.4
0.4
tons/yr
238
1164
1604
Particulate
Actual
emission rate
lb/106 Btu
0.1
(1.17)
0.1
(1.34)
0.1
(0.52)
tons/yr
59
(694)
291
(3901)
401
(2093)
Allowable
emission rate
lb/106 Btu
0.1
0.1
0.1
tons/yr
59
291
401
a Based on heat rates, AP-42 Emission Factors, and a coal analysis of 11.0% ash, 1.5% sulfur, and 12,000 Btu/lb.
Numbers in parentheses indicate potential emissions resulting from total conversion to coal firing without the
installation of additional control equipment.
£>•
I
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4.13 MUSTANG PLANT
4.13.1 Plant Description
The Mustang power plant (owned and operated by the Oklahoma
Gas and Electric Company) is located in Oklahoma City, Oklahoma,
which is part of the Central Oklahoma Intrastate Air Quality
Control Region (AQCR 184).
Mustang has four Babcock & Wilcox boilers. Boilers 1
through 4 were placed in commercial operation in 1950, 1951,
1955, and 1959, respectively. Their continuous generating capac-
ities (in the same order) are 60, 58, 114, and 273 MW. The
heights of the individual stacks serving these boilers are 250,
250, 167, and 188 feet. Boilers 1 and 2 are front-firing, pul-
verized-coal units designed to fire coal or natural gas without
derating. Boilers 3 and 4 are front-firing gas boilers designed
to fire fuel oil and natural gas, and they would suffer a 50
percent derate if coal were fired. None of the boilers is equipped
to control particulate or SO- emissions.
Only Boilers 1 and 2 are evaluated for coal conversion.
Table 4-116 presents additional unit design and operating data on
these boilers, and Figure 4-20 shows a site plan of the entire
plant.
4.13.2 Fuel Supply And Characteristics
The Mustang plant is currently firing natural gas in Boilers
1 and 2. In 1975, the two boilers fired 5285 million cubic feet
of gas. Coal, fired only on an emergency standby basis, has
never been fired continuously. The plant has purchased coal only
twice, in 1954 from the Leavell Coal Company and in 1963 from the
Benbow Coal Company. Oklahoma Gas and Electric supplies its own
natural gas. The latest available fuel analyses and costs are
presented in Tables 4-117 and 4-118.
MUSTANG POWER PLANT 4-168
-------
TABLE 4-116. DESIGN AND OPERATING DATA FOR THE MUSTANG POWER PLANT
G
O
O
S
n
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input, 106 Btu/hc
Stack height, ft above grade
Flue gas rate maximum, acfm
Flue gas temperature, °F
Emission controls
Coal firing3
1
60
7133
38.6
1
B&W
1950
27
648
250
134,115
290
None
2
58
7868
44.2
2
B&W
1951
27
648
250
134,115
290
None
.t.
I
Information from Power Plant Survey Form (Appendix M)
B&W - Babcock and Wilcox.
Based on coal heating value of 12,000 Btu/lb.
vo
-------
o
o
o
o
COOLING
TOWERS
O
o
o
o
WASTE-
COOLING TOWER WATER
PIT
O
o
o
o
TANKS D
OO
PRECIPITA-
TOR
O
o
o
o
REGULATOR MO
METERING STATIONS
TRANSPORTrj
HOUSE L-J
H 1 1
H 1-
H 1
4 t-
-I 1 1-
138-KV
SUBSTATION
X— X — x
X — <
r— — x— | — -— X — — i
66 -KV M I
, SWITCHYARD | j SWITCHYARD J
Ly - X - X— J I— X - X - X— 1
Figure 4-20. Site plan of the Mustang power plant.
MUSTANG POWER PLANT
4-170
-------
TABLE 4-117. ANALYSES OF FUEL USED AT THE
MUSTANG POWER PLANT
Analysis
Heating value
Sulfur
Ash
Coala
12,000 Btu/lb
3.5%
6.0%
Natural gas
1,037 Btu/ft3
Average analysis of two prior coal purchases.
Information from Power Plant Survey Form (Appendix M).
TABLE 4-118. COSTS OF FUEL AT THE MUSTANG POWER PLANT
Type of purchase
Fuel cost,3 $/10 Btu
Oklahoma Gas and Electric
(owner of the power plant)
1.343 (natural gas)
Information from Electrical Week magazine, March 1978.
4.13.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 184
as Priority I with respect to particulate emissions and Priority
III with respect to sulfur oxide emissions.
Section 6.2 (Figure I) of the Oklahoma Regulations limits
particulate emissions from the Mustang plant to 0.25 lb/10 Btu
heat input. Section 16.21 of these regulations sets forth the
following ambient sulfur dioxide (S0_) limits: 1350 ug/m in a
3
5-minute period in any 1 hour, a 1-hour average of 1200 yg/m , a
3 3
3-hour average of 650 yg/m , or a 24-hour average of 130 ug/m .
If Boilers 1 and 2 are converted to coal firing, Oklahoma will
require Mustang to comply with State New Source Performance
Standards (1.2 Ib S02/106 Btu) under Section 16.321(c).
MUSTANG POWER PLANT
4-171
-------
Table 4-119 summarizes emission rates and applicable regula-
tions for Mustang Boilers 1 and 2 while firing natural gas.
Air Quality Monitoring Data—
No ambient S02 or particulate monitoring data are available.
4.13.4 Plant Programs for Complying with Emission Regulations
Mustang Boilers 1 and 2 are in compliance with S02 and
particulate emission regulations when firing natural gas. The
boilers will not remain in compliance with the particulate emis-
sion regulation when high- or low-sulfur coal is burned. The
plant has formulated no compliance plans in the event Boilers 1
and 2 are ordered to fire coal.
4.13.5 Analysis of Coal Conversion Potential
Coal Availability --
The Mustang plant's two earlier sources of coal were located
in Oklahoma (Producing Districts 14 and 15). Discussions with
producers in these districts indicate a current surplus capacity
and the ability to provide any necessary additional capacity on
short notice.
If Boilers 1 and 2 must comply with the State New Source
Performance Standards covering S02 emissions, the location of the
plant may make it difficult to find low-sulfur coal sources.
Current market conditions are such that coal of the required
quality is available from underground mines in Carbon County,
Utah. It is possible that the necessary volumes could be met by
existing mining capacity. Producers in these areas report,
however, that if new underground mine capacity is required,
production will take 2 to 5 years.
Foster Associates, Inc. Present and Prospective Coal Supply
to the Mustang Plant - Oklahoma Gas and Electric Company.
May 24, 1976.
MUSTANG POWER PLANT . 4-172
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G
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TABLE 4-119.
EMISSION RATES AND REGULATIONS USING CURRENT FUEL
AT THE MUSTANG POWER PLANT
Fuel type
BOILER 1
Current fuel
Gas
BOILER 2
Current fuel
Gas
Sulfur dioxide
Actual
emission rote
lb/106 Btu
0.0006
0.0006
tons/yr
<1
<1
Allowable
emission rate
lb/106 Btu
b
b
tons/yr
b
b
Particulate
Actual
emission rate
lb/106 Btu
0.014
0.014
tons/yr
19
20
Allowable
emission rate
lb/106 Btu
0.25
0.25
tons/yr
345
363
a Based on 1975 consumption data, .l.n.17 Btu/ft3 natural qas, and emission factors from AP-*;.
Ambient SO, concentration of 1350 ug/m3 in a 5-minute period in any 1 hour; a 1-hour average of 1200 pg/m , a
3-hour average of 650 ug/m3, or a 24-hour average of 130 ug/m3.
-J
U)
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Northern Oklahoma is also a possible source of low-sulfur
coal. Traditionally, the low-sulfur, high-Btu coal in this area
has gone to the metallurgical market. A new mine under develop-
ment in Muskogee County has sufficient uncommitted tonnage to
satisfy the Mustang plant requirements. Table 4-120 presents the
coal analyses of the three sources evaluated.
TABLE 4-120.
ANALYSES OF AVAILABLE COAL FOR THE
MUSTANG POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Oklahoma
(Producing District
14 and 15)
12,000
3.5
6.0
Utah
11,600 - 12,500
0.6 - 0.7
9.0 - 10.0
Northern
Oklahoma
12,500 - 13,500
0.6 - 0.9
4.0 - 6.0
The Mustang plant is located along a spur from the Chicago,
Rock Island and Pacific Railroad, which could handle a maximum of
20 to 25 hopper cars. The deteriorated roadbed would probably
require complete rebuilding before any significant volume of coal
could be received. Coal from Oklahoma could be loaded onto the
Missouri-Kansas-Texas, Kansas City Southern, St. Louis-San
Francisco, or Missouri Pacific Railroads. Discussions with these
carriers indicate that sufficient surplus hopper car capacity is
available to transport the Mustang plant coal requirements. If
new hopper cars were needed, an 18-month leadtime would be re-
quired.
Coal from Carbon County, Utah, would be loaded onto the
Denver and Rio Grande Western Railroad and transferred to the
Atchinson, Topeka, and Santa Fe Railroad near Pueblo, Colorado,
for delivery to Oklahoma City. Some surplus hopper car capacity
MUSTANG POWER PLANT
4-174
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is available, and additional cars can be obtained from associated
carriers. Discussions with company personnel indicate that new
hopper cars can be made available with a leadtime of 6 to 9
months.
Table 4-121 presents estimated delivered coal costs.
TABLE 4-121. ESTIMATED DELIVERED COAL COSTS FOR
THE MUSTANG POWER PLANT
Price (f.o.
b. mine) , $/ton
Transportation cost, $/ton
Total cost,
Total cost,
1978 total
$/ton
$/106 Btu
cost, $/106 Btu
Oklahoma
(Producing
Districts
14 and 15)
17.17
3.49
20.66
0.861a
0.949a'd
Utah
16.25
28.19
44.44
1.916b
2.111b'
Northern
Oklahoma
30.60
3.49
34.09
1.364C
1 1.503C'd
Based on a coal with a heating value of 12,000 Btu/lb.
Based on a coal with a heating value of 11,600 Btu/lb.
Based on a coal with a heating value of 12,500 Btu/lb.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Fuel Conversion--
Certain technical factors affect conversion from natural gas
to coal. Although Boilers 1 and 2 were originally designed to
burn coal, they have never done so on a continuous basis. Con-
verting these boilers to coal burning involves overhauling all
equipment in the coal and ash handling systems, adding a gas/dust
cleaning system, and performing a major overhaul of the spur
lines and coal conveyor systems. The estimated cost and con-
struction time for Boiler 1 are $1,147,000 and 20 weeks; for
MUSTANG POWER PLANT
4-175
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Boiler 2, $1,194,000 and 20 weeks. The most expensive item and
the one requiring the longest construction time is the ash han-
dling system. The plant estimates a cost of $2,877,000 and a
construction time of 26 weeks. Total conversion cost estimated
by the plant is $10,703,000. An additional $866,000 per year is
estimated for operation and maintenance. Table 4-122 presents
fuel usage data on which these costs are based.
4.13.6 Analysis of Methods for Controlling SC>2 Emissions
Compliance with the ambient S0? regulation when firing coal
must be determined by a modeling study.
If the Mustang plant converts to coal, the State of Oklahoma
requires that Boilers 1 and 2 comply with State New Source Per-
formance Standards (1.2 lb/10 Btu heat input). In this event,
compliance can be accomplished by firing low-sulfur (0.7 percent)
coal from northern Oklahoma or from mines in Carbon County, Utah.
4.13.7 Analysis of Methods for Controlling Particulate Emissions
No particulate emission control equipment is currently
installed at the Mustang plant. If ordered to convert to coal,
neither boiler would comply with the particulate emission regu-
lation (i.e., 0.25 lb/10 Btu heat input). Compliance can be
accomplished by installation of new ESP's to serve Boilers 1 and
2. Each would have a design efficiency of 97.65 percent to meet
a 20 percent opacity regulation (i.e., approximately 0.1 lb/10
Btu). Plate areas required for the new ESP's on each boiler are
approximately 26,400 ft for high-sulfur coal firing and 55,900
2
ft for low-sulfur coal firing.
The estimated capital cost of the new ESP's on Boilers 1 and
2 is $14,149,000 ($119.91/kW) for high-sufur coal firing and
$14,865,000 ($125.97/kW) for low-sulfur coal firing; each option
includes a coal conversion cost of $10,703,000. An estimated
annual operating credit of $302,000 (0.71 mills/kWh) would result
from switching from gas to high-sulfur coal firing, and an annual
operating cost of $6,720,000 (15.72 mills/kWh) would result from
switching to low-sulfur coal firing.
MUSTANG POWER PLANT 4-176
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TABLE 4-122. COAL CONVERSION DATA FOR THE MUSTANG POWER PLANT
Boiler
No.
1
2
Total
Capacity
factor,
(1975)
%
38.6
44.2
Fuel consumption3
Type
Gas
Gas
Quantity /yr
2,575 106 ft3
2,710 106 ft3
Coal conversion data
Conv. cost,
$
10,703,000
Coal usaqe,
tons/yr
111,000
118,000
229,000
1975 consumption figures from Power Plant Survey Form (Appendix M).
Based on 1975 capacity factors and 12,000 Btu/lb coal.
As reported by plant (no breakdown available); escalated to 1978 dollars
by PEDCo.
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4.13.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting to coal firing, the
recommended strategy is to fire low-sulfur coal and install new
ESP's to comply with SO» and particulate emission regulations.
Table 4-123 presents a cost assessment for new ESP's on Boilers 1
and 2. Table 4-124 presents emission rates and regulations for
these boilers, based on the recommended strategy.
MUSTANG POWER PLANT 4-178
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TABLE 4-123. COST ASSESSMENT FOR EMISSION CONTROLS
AT THE MUSTANG POWER PLANT
Emission control alternative
S02 control
Limestone scrubbing
Sodium solution regenerable
Particulate control
d
Electrostatic precipitator
installation
High-sulfur coal Boilers 1 and 2
Low-sulfur coal0 Boilers 1 and 2
Time
rcqui rt-d ,
months
NA
NA
Capital cost'
S 106
14. IS
14.87
S/kW
119.91
125.97
Annual! zed cost
Fuel,
mills/kWh
(5.02)
11.05
OSM,
mil Is/kWh
2.68
2.70
Fixed,
mills/kWh
1.63
1.97
Total .
mil Is/kWh
(0.71)
15.72
S 106
(0.30)
6.72
Includes coal conversion cost of $10,703,000.
J ESP design based on coal with 3.0% sulfur, 6.0% ash, 12,500 Btu/lb.
c Low-sulfur coal analysis for ESP design is 0.7% sulfur, 6% ash, 12,500 Btu/lb.
Costs are in January 1978 dollars; have not been escalated through project completion and do not include
replacement power.
NA - Not applicable.
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TABLE 4-124. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE MUSTANG POWER PLANT
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Fuel type
BOILER 1
Alternate fuel
Coald
BOILER 2
Alternate fuel
Coald
Sul fur dioxide
Actual a
emission rate
lb/106'Btu
5.54
(1.06)
5.54
(1.06)
tons/yr
7382
(1412)
7847
(1501)
Allowable
emission rate
lb/106 Btu
b
(1.20)
b
(1.20)
tons/yr
b
b
Particulate
Actual
emission rate
lb/106 Btu
O.lc
(4.25)
0.1C
(4.25)
tons/yr
133C
(5661)
141C
(6018)
Al lowable
emission rate
lb/106 Btu
0.25
0.25
tons/yr
333
353
a Based on 12,000 Btu/lb, 3.5% sulfur, 6.0% ash coal. 3
b Ambient SO2 concentration of 1350 pg/m^ in a 5-minute period in any 1 hour: a 1-hour average of 1200 pg/m , a 3-hour
average of 650 pq/m^ or a 24-hour average of 130 ug/m .
0 Based on new ESP's, each having a design efficiency of 97.65%.
d Numbers in parentheses for SO2 represent estimated and allowable emissions based on 0.7% S (12,500 Btu/lb) coal and meeting
New Source Performance Standards. Numbers in parentheses for particulates indicate potential emissions resulting from coal
conversion without control equipment.
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4.14 POSSUM POINT POWER PLANT
4.14.1 Plant Description
The Possum Point power plant (owned and operated by the
Virginia Electric and Power Company) is located on the Potomac
River near Dumfries, Prince William County, Virginia. This area
is part of the National Capital Interstate Air Quality Region
(AQCR 047).
The five boilers at Possum Point now burn residual fuel oil,
but Boilers 1 through 4 can fire coal or oil without derating.
These boilers, manufactured by Combustion Engineering, have
nameplate generating capacities of 69, 69, 114, and 239 MW,
respectively. (Summer peaking capabilities are 74, 69.2, 101,
and 232.9 MW.) Each boiler exhausts through its own 175-ft
stack, and each is equipped with an electrostatic precipitator
(ESP). Boiler 5, also manufactured by Combustion Engineering, is
designed to fire only residual fuel oil. This 882-MW (summer
capability of 805 MW) boiler has a mechanical collector with a
design efficiency of 91.2 percent. It exhausts through a 358.5-ft
stack.
Table 4-125 presents additional unit design and operating
data, and Figure 4-21 shows a site plan of the plant. Only
Boilers 2, 3, and 4 are evaluated for coal conversion in this
report.
4.14.2 Fuel Supply and Characteristics
In 1975, the plant fired 6,838,170 bbl of fuel oil purchased
from Exxon Oil Company and New England Petroleum Corporation.
Tables 4-126 and 4-127 show the analysis of the current fuel and
fuel cost.
POSSUM POINT POWER PLANT 4-181
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TABLE 4-125. DESIGN AND OPERATING DATA FOR THE POSSUM POINT POWER PLANT
Item
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer6
Year placed in service
Max. coal consumption, tons/h
Max. heat input, f 106 Btu/h
Stack height, ft above grade
Flue gas rate maximum, acfm
Flue gas temperature, °F
Emission controls
Coal firing
2
69b
7,244
48.0
2
CE
1951
29.6
937
175
273,726
303
ESP
3
114s
5,058
34.0
3
CE
1955
38.5
1,051
175
338,099
277
ESP
4
239d
7,043
57.0
4
CE
1962
78.3
2,206
175
650,385
265
ESP
G
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CD
to
a Information from Power Plant Survey (Appendix N).
b
Summer capacity is 69.2 MW.
Summer capacity is 101 MW.
Summer capacity is 232.9 MW.
g
CE = Combustion Engineering -
Values given to Virginia's Air Pollution Control Board by plant officials,
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Figure 4-21. Site plan of Possum Point power plant,
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TABLE 4-126. ANALYSIS OF FUEL FIRED AT THE
POSSUM POINT POWER PLANT
Analysis
Heating value,
Btu/gal
Sulfur, %
Fuel oil consumption
a
146,680
1.4
a Information from Power Plant Survey Form (Appendix N).
TABLE 4-127. FUEL COST AT THE POSSUM POINT POWER PLANT
Type of purchase
Contract
Fuel cost,a $/106
Btu
Oil
2.334
a
Information from Electrical Week magazine, March 1978.
4.14.3 Atmospheric Emissions
The Possum Point power plant has been designated by the
Environmental Protection Agency as Priority I with respect to
emissions of sulfur oxides and particulates. Current Virginia
regulations limit particulate emissions to 0.1 lb/10 Btu heat
input for all fuels.
The Virginia SO- emission regulation is determined on a
6
plant basis by the equation S = 1.06 lb/10 Btu x K, where S is
the allowable sulfur rate in Ib/h, and K is the plant's heat input
in 10 Btu/h. Boiler 5, however, is a new unit and must comply
with the New Source Performance Standard of 0.8 lb/10 Btu, which
is more stringent than the State regulation covering the entire
plant. Therefore, Boilers 1 through 4 can fire fuels with a
sulfur content of 1.5 lb/10 Btu or less and still comply with
the State regulation. Table 4-128 summarizes emission rates and
regulations for the Possum Point plant when firing current fuel.
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TABLE 4-128. EMISSION RATES AND REGULATIONS AT THE
POSSUM POINT POWER PLANT WHEN BURNING CURRENT FUEL
Fuel type
BOILER 2
Current fuel
Oil
BOILER 3
Current fuel
Oil
BOILER 4
Current fuel
Oil
Sulfur dioxide
Actual
emission rate
lb/106 Btu
1.50
1.50
1.50
tons/yr
2,660
2,823
9,380
Allowable
emission rate
lb/106 Btu
1.5
1.5
1.5
tons/yr
2,660
2,823
9,380
Particulate
Actual
emission rate
lb/106 Dtu
0.0545
0.0545
0.0545
tons/yr
97.0
103
341
Allowable
emission rate
lb/106 Btu
0. 10
0.10
0. 10
tons/yr
177
188
625
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The allowable sulfur dioxide emission rate for the whole plant is 1.06 lb/10u Btu. Boiler 5 must meet the New Source
Performance Standard of 0.8 lb/10^ Btu, but the allowable sulfur dioxide emission rate for the rest of the plant is
1.5 lb/106 Btu.
Emissions based on 1975 operating data, boiler heat rates, and an oil analysis of 1.4 percent sulfur and 146,680
Btu/gal.
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Air Quality Monitoring Data—
Ambient S0? monitoring data were collected at 58 stations in
the vicinity of Possum Point, and ambient suspended particulate
monitoring data were collected at two stations in the area (Fig-
ure 4-22). These data, collected from July 1974 through June
1975, are used to characterize ambient air quality in the vicinity
of the Possum Point plant.
The monitoring data indicate that all State and Federal
ambient particulate standards were met. The highest annual
geometric mean was 46 yg/m , and the 24-hour maximum was 113
yg/m .
Measurements also show that ambient SO- standards were met.
The maximum annual arithmetic mean was 0.011 ppm, and the 24-hour
maximum was 0.104 ppm.
Table 4-129 compares Federal and State ambient air quality
standards and the maximum recorded values.
4.14.4 Plant Programs for Complying with Emission Regulations
Plant officials have formulated no plans to meet either
particulate or S02 emission regulations in the event boilers are
converted to coal firing.
4.14.5 Analysis of Coal Conversion Potential
Coal Availability —
Former coal sources in southern West Virginia and eastern
Kentucky (Producing Districts 7 and 8) indicate that a surplus of
low-sulfur (0.70%) coal is currently available. This sulfur
content would allow the Possum Point plant to meet State and
Federal S0_ regulations. Table 4-130 presents a typical analysis
of coal from these districts.
Foster Associates, Inc. Present and Prospective Coal Supply to
the Possum Point Plant - Virginia Electric and Power Company.
June 18, 1976.
POSSUM POINT POWER PLANT 4-186
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S02 MONITORING STATIONS
PARTICULATE
MONITORING STATIONS
Figure 4-22. Ambient air monitoring stations in the vicinity
of the Possum Point power plant.
POSSUM POINT POWER PLANT
4-187
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TABL^ 4-129 COMPARISON OF FEDERAL AMD STATE AMBIENT AIR QUALIFY STANDARDS
WITH THE MAXIMUM RECORDED VALUES NEAR THE POSSUM POINT POWER PLANT
Pollutant
Particulates, yg/m
Annual geometric
mean
24-hour maximum
S02, ppm
Annual arithmetic
mean
24-hour maximum
3-hour maximum
Ambient Air Quality Standards
Federal
Primary
75
260
0.030
0.140
0.500
Secondary
60
150
0.500
State
Primary
75
260
0.030
0.140
0.500
Secondary
60
150
0.500
Maximum
recorded
values
46
113
0.011
0.104
0.338
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TABLE 4-130. ANALYSIS OF AVAILABLE COAL FOR THE
POSSUM POINT POWER PLANT
Analysis
Southern
West Virginia
Kentucky
and eastern
Heating Value, Btu/lb
Sulfur, %
Ash, %
13,100
0.70
6.0
The Possum Point plant has terminated railway services with
Richmond, Fredricksburg, and Potomac (RF&P) rail lines, and 70
percent of the railroad siding has been removed; however, ade-
quate space is available for construction of new rail facilities.
The Chessie System (C&O-B&O) would transport the coal from the
mines in West Virginia to the RF&P lines near Doswell, Virginia,
for delivery to the plant. There would be no problem with coal
hoppers, because the Chessie System is installing new cars.
Table 4-131 presents delivered costs of coal for the Possum
Point plant from Producing Districts 7 and 8.
TABLE 4-131.
ESTIMATED COSTS OF COAL FOR THE POSSUM POINT
POWER PLANT
Price, f.o.b. mine, $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost,a $/106 Btu
1978 total cost,b $/106 Btu
Southern West Virginia and
eastern Kentucky
40.00
10.36
50.36
1.922
2.118
Based on 13,100 Btu/lb.
Foster Associates values escalated to 1978 dollars.
POSSUM POINT POWER PLANT
4-189
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Technical Factors Affecting Fuel Conversion—
Although Boilers 2, 3, and 4 were designed to fire coal,
they have not done so since 1969. Reconversion of these boilers
to coal firing would involve extensive maintenance or rebuilding
of all coal handling equipment, conveyors, bunkers, pulverizers,
crushers, and controls. Also, the coal storage area was reduced
by the addition of Boiler 5. The estimated coal conversion cost
of $691,000 includes costs of a locomotive and a tractor. Table
4-132 presents coal conversion data.
4.14.6 Analysis of Methods for Controlling S02 Emissions
Low-sulfur Coal--
The Possum Point power plant could meet the Virginia regula-
tion limiting sulfur dioxide emissions by firing low-sulfur
(0.70%) coal from southern West Virginia and eastern Kentucky.
Since this coal is available to the plant, flue gas desulfuriza-
tion (FGD) systems are not evaluated.
4.14.7 Analysis of Methods for Controlling Particulate Emission
Boilers 2, 3, and 4 are equipped with Research-Cottrell
electrostatic precipitators with efficiencies of 96 percent.
When firing coal, these three boilers cannot comply with Virginia
particulate emission standards. To achieve compliance with these
regulations, Boilers 2, 3, and 4 would have to be equipped with
new ESP's with efficiencies of approximately 97.4 percent and
plate areas of 155, 180, and 288 thousand square feet, respec-
tively.
The estimated capital cost of installing these new ESP's is
$21,867,000 ($54.25/kW); this includes $691,000 for coal conver-
sion costs. The annual operating cost, which includes a fuel
credit (in switching from oil to coal firing), is $919,000 (0.52
mills/kWh).
POSSUM POINT POWER PLANT 4-190
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TABLE 4-132. COAL CONVERSION DATA FOR THE POSSUM POINT POWER PLANT
Boiler
No.
2
3
4
Total
Capacity
factor
(1975),
%
48.0
34.0
57.0
Fuel consumption3
Type
Oil
Oil
Oil
Quantity /yr
577,850 bbl
551,950 bbl
1,970,600 bbl
Coal conversion data
Conv. cost,
$
137,000
213,000
341,000
691,000
Coal usage, c
tons/yr
138,000
150,000
444,000
732,000
Information from Power Plant Survey Form (Appendix N).
Costs given by Virginia Electric and Power Company to the FEA in the
letter dated March 17, 1975; values escalated to January 1978 dollars,
Coal required for conversion to total coal firing, based on 1975
capacity factors.
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4.14.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to coal
firing, the recommended strategy is to fire low-sulfur (0.70%)
coal from southern West Virginia and eastern Kentucky and to
install new ESP's on Boilers 2, 3, and 4 to comply with appli-
cable S02 and particulate emission regulations. Table 4-133
shows a cost comparison of the control alternatives evaluated for
the Possum Point plant. Table 4-134 presents emission rates and
regulations for the recommended strategy.
POSSUM POINT POWER PLANT 4-192
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TABLE 4-133. COST ASSESSMENT FOR EMISSION CONTROLS
AT THE POSSUM POINT POWER PLANT - 1978
Emission control
alternative
S02 Control
Low-sulfur coalc
Limestone scrubbing
Sodium solution
regenerable
Particulate Control
Electrostatic precipi-
tator installation^
Boiler 2
Boiler 3
Boiler 4
Total
Time
required ,
months
NA
NA
30
30
30
36
Capital cost3
$ 106
6.05
6.45
9.37
21.87
$/kW
87.38
63.90
40.21
54.25
Annualized cost
Fuel,
mills/kWh
Included b
(2.24)
1.29
(3.17)
(2.24)
O&M,
mills/kWh
elow in ESP
1.14
1.11
0.43
0.66
Fixed,
mills/kWh
calcula t io
3.97
3.68
1.24
2.10
Total.
mills/kWh
ns
2.87
6.08
(1.50)
0.52
$ IO6
0.84
1.83
(1.75)
0.92
Includes coal conversion cost of 5137,000 for Boiler 2, 5213,000 for Boiler 3, and $341,000 for Boiler 4.
Installation cost does not include the cost for the removal of old ESP's.
Numbers in parentheses indicate credits.
^
Analysis of coal is 1.25 percent sulfur, 11 percent ash, and 12,500 Btu/lb.
Costs represent January 1978 dollars; they are not escalated through project completion and do not include
replacement power.
NA - Not applicable.
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TABLE 4-134. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE POSSUM POINT POWER PLANT
Fuel type
BOILER 2
Alternate fuel
Coal
BOILER 3
Alternate fuel
Coal
BOILER 4
Alternate fuelb
Coal
Sulfur dioxide
Actual
emission rate
lb/106 Btu
1 .9
(1.9)
1.9
(1.9)
1.9
(1.9)
tons/vr
3,258
(3,258)
3,543
(3.543)
10,458
(10,458)
Al lowable
emission rate3
lb/106 Btu
1.9
1.9
1.9
tons/yr
3,258
3,543
10,458
Particula te
Actual
emission rate
lb/106 Btu
0.1
(1.45)
0.1
(0.95)
0.1
(0.59)
tons/yr
171
(2,494)
186
(1,778)
550
(1,930)
Al lowable
emission rate
lb/106 Btu
0. 1
0. 1
0.1
tons/yr
171
186
550
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a The allowable sulfur dioxide emission rate for the whole plant is 1.06 lb/10 Btu. Since Boiler 5 must meet the new source
regulation of 0.8 lb/106 Btu, the allowable sulfur dioxide emission rate for the rest of the plant is 1.9 lb/106 Btu.
b Emissions based on 1975 operating data, boiler heat rates, a coal analysis of 1.25 percent sulfur, 11 percent ash, and
12,500 Btu/lb, and individual ESP's with calculated efficiencies of 81, 87, and 92 percent for Boilers 2, 3, and 4,
respectively. Numbers in parentheses indicate potential emissions resulting from a total conversion to coal firing with-
out the installation of additional control equipment.
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4.15 RAVENSWOOD PLANT
4.15.1 Plant bescription
The Ravenswood power plant (owned and operated by the
Consolidated Edison Company of New York) is located on the east
bank of the East River in New York City in Queens County. This
area is part of the New Jersey/New York/Connecticut Interstate
Air Quality Control Region (AQCR 043).
The Ravenswood plant consists of three boilers. Boilers 10
and 20 can only fire oil or gas; and Boiler 30 can fire oil, gas,
or coal on a continuous basis. Since Boilers 10 and 20 cannot
fire coal, only Boiler 30 is evaluated for conversion to coal
firing. Boiler 30, a split furnace, was manufactured by Combus-
tion Engineering and began service in 1965. It has a maximum
continuous generating capacity of 800 MW while firing coal. The
boiler is equipped with a mechanical collector and an electro-
static precipitator (ESP); it exhausts through a 515-ft stack.
Additional unit design and operating data are presented in
Table 4-135. A site plan of the plant is shown in Figure 4-23.
4.15.2 Fuel Supply and Characteristics
All of the boilers at Ravenswood currently fire oil and
natural gas. In 1975, Boiler 30 fired approximately 7.64 million
bbl of oil and 73 million ft of gas. The fuels were purchased
from a central tank farm, which was supplied by various distribu-
tors. Analyses of the fuels are shown in Table 4-136, and cost
data are presented in Table 4-137.
RAVENSWOOD POWER PLANT 4-195
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TABLE 4-135. DESIGN AND OPERATING DATA FOR
THE RAVENSWOOD POWER PLANT
Item
Coal firing'
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975), %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
c 6
Max. heat input, 10 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
30
800
7443
63.1
3
CE
1965
321
7704
515
4,300,000
700
Mech. collector
and ESP
a Information from Power Plant Survey Form (Appendix 0) .
Boilers 30 N and 30 S will be treated as one boiler.
Combustion Engineering.
c Based on a coal heating value of 12,000 Btu/lb.
RAVENSWOOD POWER PLANT
4-196
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EAST RIVER X"^
i
I
o
1
o:
o
>-
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TABLE 4-136. ANALYSES OF FUEL BURNED AT THE
RAVENSWOOD POWER PLANT
Analysis
Heating value
Sulfur
Fuel oil
144,241 Btu/gal
0.27%
Natural gasa
1025 Btu/ft3
Information from Power Plant Survey Form (Appendix 0).
TABLE 4-137. COSTS OF FUEL AT THE RAVENSWOOD POWER PLANT
Type of purchase
Contract
Fuel cost,3 $/106 Btu
Oil
2.204
Natural gas
1.298
a Information from Electrical Week magazine, February 1978.
4.15.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 043
as Priority I with respect to emissions of particulates and
sulfur oxides. Part 227.3 (c) of the New York Regulations limits
particulate emissions from oil or coal firing in Boiler 30 to
0.10 lb/10 Btu heat input. The regulations under Part 225,
Table I, limit the sulfur content in residual oil to 0.30 per-
cent, and the SO2 emissions from coal firing to 0.40 lb/10 Btu.
Table 4-138 summarizes emission rates and applicable regulations
for the Ravenswood plant while firing oil and natural gas.
Air Quality Monitoring Data --
Ambient particulate and S02 monitoring data for July 1973
through June 1974 were collected at 12 stations in the Queens
area. These data were used to characterize the ambient air
quality in the vicinity of the Ravenswood power plant.
The City of New York, Dept. of Air Resources, Bureau of Techni-
cal Services. Fiscal Report, July 1, 1973 - June 30, 1974.
RAVENSWOOD POWER PLANT
4-198
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s:
o
o
a
o
s
w
33
TABLE 4-138.
EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT FUEL USAGE
AT THE RAVENSWOOD POWER PLANT
Fuel type
BOILER 30
Current fuel
Oil
Gas
Sulfur dioxide
Actual a
1 emission rate
lb/106 Btu
0.29
0.0006
tons/yrb
6805
<1
Allowable
emission rate
lb/106 Btu
0.33
0.33
tons/yrb
7744
12
Particulate
Actual
emission rate
lb/106 Btu
0.06
0.015
tons/yrb
1284
<1
Aiiowaoie
emission rate
lb/106 Btu
0.10
0.10
tons/yr"
2140
4
Based on AP-42 emission factors and an oil analysis of 0.27% S and 144,241 Btu/gal. The heating value used for gas is
1000 Btu/ft3.
Based on 1975 fuel consumption.
I
h-1
VD
-------
Measurements indicate that the annual geometric mean stan-
dard for particulates was violated at 10 stations. Five of the
stations recorded values that violated the Federal primary stan-
dard. The Federal secondary standard was violated at nine of the
s
stations. The maximum annual geometric mean concentration of 120
yg/m was recorded at the Bowery Bay station.
The 24-hour average particulate standard was also violated
at 10 stations. Four of the stations recorded values that vio-
lated Federal and State primary standards. The Federal secondary
standard was violated at six of the stations. (There is no State
secondary standard.) The maximum 24-hour average concentration
of 493 yg/m was recorded at the Queens College monitor.
No Federal or State SO- standards were violated at any of
the 12 monitoring stations during the July 1973 through June
1974 period. The maximum recorded annual average and 24-hour
values of 75 yg/m and 339 yg/m , respectively, were measured at
the Tallman Island and Bowery Bay monitors.
Figures 4-24 and 4-25 show the 12 monitoring stations and
the maximum values recorded at each station during the 1-year
period. Table 4-139 summarizes the Federal and State ambient air
quality standards and maximum concentrations recorded near the
Ravenswood plant.
4.15.4 Plant Programs for Complying with Emission Regulations
When the Ravenswood power plant fires oil and natural gas,
it complies with the New York particulate and S02 emission regu-
lations. Consolidated Edison has formulated no plans for com-
pliance in the event Boiler 30 is ordered to switch to coal
firing.
4.15.5 Analysis of Coal Conversion Potential
2
Coal Availability —
Coal is available from central Pennsylvania (Producing
District 1) and eastern Kentucky (Producing District 8). Both
2
Foster Associates, Inc. Present and Prospective Coal Supply to
the Arthur Kill, Astoria, and Ravenswood Plants - Consolidated
Edison Company of New York, Inc. September 9, 1976.
RAVENSWOOD POWER PLANT 4-200
-------
NEW JERSEY
9 MANUAL STATION
A TELEMETRY STATION
NEW YORK
^. .Jv .
BOWER V'5X
-------
NEW JERSEY
O MANUAL STATION
A TELEMETRY STATION
0.017
0.06
Figure 4-25. Sulfur dioxide monitoring data for the
Ravenswood power plant.
Upper number: annual average, yg/m
Lower number: maximum 24-hour average/ yg/m"
RAVENSWOOD POWER PLANT
4-202
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w
o
o
o
TABLE 4-139. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
WITH THE MAXIMUM VALUES RECORDED NEAR THE RAVENSWOOD POWER PLANT
(Concentration in
so2
Annual average
Maximum 24-hour
average
Particulate
Annual geometric
mean
Maximum 24-hour
average
Ambient air quality standards
Federal
Primary
80
365
75
260
Secondary
60
150
State
Primary
80
365
65
250
Secondary
Maximum
recorded
values
75
339
120
493
f
§
t-3
O
OJ
-------
areas currently have a surplus of coal; however, if coal demand
warrants the need for the development of new mines, a minimum of
2 years would be required before initial coal supplies would be
available.
Table 4-140 shows characteristics of coal available to the
Ravenswood plant.
TABLE 4-140. ANALYSES OF COAL AVAILABLE TO
THE RAVENSWOOD POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Central Pennsylvania
12,000 - 12,500
2 - 2.5
9-15
Eastern Kentucky
12,000 - 12,500
1 - 1.5
6-12
When the Ravenswood plant was coal fired, barges were used
to deliver coal to the plant from piers in the New York Harbor
area. Coal produced in central Pennsylvania would be loaded onto
lines of the Consolidated Rail Corporation (ConRail) and then
transported to the ConRail coal pier at Reading, New Jersey, for
delivery to the New York Harbor area. Coal produced in the
eastern Kentucky area would be loaded onto the Chessie System,
and then transferred to ConRail for rail-to-barge transfer at the
Port Reading coal pier.
Both rail carriers have indicated that there are no major
transportation problems concerning coal deliveries to the Port
Reading pier. Barge shipments, however, could present some
difficulties because of the questionable availability of barges.
Most barge companies in the area have either sold or scrapped
their barges because of the recent decline in coal traffic. If
market conditions warrant the need for new barges, 9 to 18 months
would be required for construction and delivery.
RAVENSWOOD POWER PLANT
4-204
-------
Cost estimates for coal delivered to Ravenswood are shown in
Table 4-141. The f.o.b. mine prices are representative of cur-
rent contract purchases. Rail transportation costs include 7000-
ton volume tariffs (ConRail). Barge rate estimates were deter-
mined by discussions with marine transportation companies.
TABLE 4-141. ESTIMATED DELIVERED COAL COSTS FOR THE
RAVENSWOOD POWER PLANT
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Rail :
Barge :
Total costs, $/ton
Total cost, $/10 Btu
1978 total cost, $/106 Btu°
Central
Pennsylvania
19.00
6.91
1.00
26.91
1.076a
1.186°
Eastern
Kentucky
18.25
10.68
1.00
29.93
1.247b
1.374°
Based on a coal with a heating value of 12,500 Btu/lb.
Based on a coal with a heating value of 12,000 Btu/lb.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Fuel Conversion--
Boiler 30 has not fired coal since 1970. Converting the
boiler back to coal firing would require refurbishing the coal
and ash handling equipment. Specific items that would need
overhauling are the bottom/fly ash systems, raw coal system,
pulverizer system and burners, and controls. The fly ash silo
would also need to be restored. Cost of restoring this equipment
is estimated to be $863,000 (January 1978 dollars), based on
Consolidated Edison's letter to the FEA. Coal conversion data
are presented in Table 4-142.
RAVENSWOOD POWER PLANT
4-205
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TABLE 4-142. COAL CONVERSION DATA FOR THE RAVENSWOOD POWER PLANT
Boiler
NO.
30
Total
Capacity
factor
(1975) ,
%
63.1
Fuel consumption
Type
Oil
Gas
Quantity /yr
7,643,900 bbl
72,900,000 ft3
Coal conversion data h
Conv. cost,
$
863,000
863,000
Coal usage,
tons/yr
2,305,000
2,305,000
1
w
2
to
5
O
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O
M
tr1
^
1975 consumption figures.
Coal required for conversion to total coal firing; based on coal heat rate reported
by Consolidated Edison, 63.1% capacity factor, and coal heating value of 12,000 Btu/lb.
i
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4.15.6 Analysis of Methods for Controlling SO., Emissions
Low-sulfur Coal—
Coal having characteristics of approximately 0.25 percent
sulfur and 12,000 Btu/lb would be required to meet the SO7
c *•
emission regulation of 0.40 lb/10 Btu. Coal of this analysis is
not available to the Ravenswood plant.
Flue Gas Desulfurization (FGD)—
A sodium solution regenerable and a limestone scrubbing
system are evaluated for control of SO- emissions from Boiler 30.
The systems are based on coal characteristic of Producing Dis-
trict 8 and would require approximately 84 percent removal capa-
bility to meet the S02 emission regulation of 0.40 lb/10 Btu.
The estimated capital cost of retrofitting Boiler 30 with a
sodium solution regenerable system is $116,449,000 ($145.56/kW),
which includes a coal conversion cost of $863,000. The annual
operating cost is estimated to be $9,431,000 (2.13 mills/kWh),
which includes a fuel credit in switching from oil/gas firing to
coal firing. The estimated capital cost of retrofitting Boiler
30 with a limestone scrubbing system is $89,935,000 ($112.42/kW).
The annual operating cost, which includes a fuel credit, is
estimated to be $16,743,000 (3.79 mills/kWh).
Costs of a sodium solution regenerable and a limestone
scrubbing system are represented in January 1978 dollars and are
not escalated through project completion.
4.15.7 Analysis of Methods for Controlling Particulate Emissions
Boiler 30 is equipped with a mechanical collector and an
ESP. The ESP has a total plate area of 1,008,000 ft2. Tests
conducted while the boiler fired coal showed an average ESP
efficiency of 99.3 percent. Since this efficiency would allow
compliance with the particulate regulation if coal is fired
again, no additional ESP is evaluated for Boiler 30. If the
boiler were converted to coal, however, new emission tests should
be run to verify the compliance status because nonuse could cause
deterioration of the ESP.
RAVENSWOOD POWER PLANT 4-207
-------
Venturi scrubbers to be used in conjunction with the FGD
systems are evaluated to assure particulate control while firing
1.5 percent sulfur coal from eastern Kentucky. Costs of the
Venturis are included in the FGD estimates.
4.15.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting Boiler 30 to coal
firing, the recommended strategy is to fire coal from eastern
Kentucky and to install a limestone/venturi scrubbing system.
This alternative would satisfy the S02 and particulate emission
regulations.
An assessment of the control methods evaluated for Boiler 30
is summarized in Table 4-143. Emission rates and regulations
based on the recommended strategy are presented in"Table 4-144.
RAVENSWOOD POWER PLANT 4-208
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S
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o
D
tl
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50
f
>
z
TABLE 4-143. ESTIMATED COSTS OF EMISSION CONTROL OPTIONS
AT THE RAVENSWOOD POWER PLANT - 1978
Emission control alternative
Combined SO-/particulate control
Low-sulfur coal
Limestone scrubbing
Sodium soln. regenerablec
Particulate control
ESP installation
Flue gas conditioning
Time
required ,
months
NA
40
40
NA
NA
Capital cost
106 S
89.94
116.45
SAW
112.42
145.56
Annualized cost
Fuel,
mills/kWh
(5.91)
(5.91)
O&M,
mills/kWh
5.76
2.93
Fixed ,
mills/kWh
3.94
5.11
Total
mills/kWh
3.79
2.13
10& $
16.74
9.43
Includes coal conversion cost of $863,000.
Numbers in parentheses indicate credits.
c Systems are based on coal having 1.5% S, 12% ash, and 12,000 Btu/lb. Costs pertain to Boiler 30; they represent
January 1978 dollars; they are not escalated through project completion and do not include replacement power.
NA - Not applicable.
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cn
2
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ra
13
TABLE 4-144. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE RAVENSWOOD POWER PLANT
Fuel type
BOILER 30
Alternate fuel
Coal
Sulfur dioxide
i Actual
emission rate
lb/106 Btu
0.40
(2.38)
tons/yr
11,040
(65,693)
Allowable
emission rate
lb/106 Btu
0.40
tons/yr
11,040
Particulate
Actual a
emission rate
lb/106 Btu
0.06
(0.06)
tons/yr
1645
(1645)
Aliowaoie
emission rate
lb/106 Btu
0.10
tons/yr
2742
a Numbers in parentheses represent emissions without additional control equipment; particulate emissions are based on
an actual (average) ESP test result of 99.3%. If Boiler 30 were converted to coal firing again, additional testing
would have to be conducted to determine the compliance status.
I
to
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4.16 RIDGELAND PLANT
4.16.1 Plant Description
The Ridgeland power plant (owned and operated by the Common-
wealth Edison Company) is located on the north bank of the Chicago
Sanitary and Ship Canal in Stickney, Illinois. This area is part
of the Metropolitan Chicago Interstate Air Quality Control Region
(AQCR 067).
The six Babcock & Wilcox cyclone boilers at Ridgeland are
capable of firing coal, residual oil, and natural gas. Boilers 1
and 2 have been in service since 1951, Boilers 3 and 4 since
1950, Boiler 5 since 1953, and Boiler 6 since 1955. The six
boilers are coupled to four turbines: Boilers 1 and 2 and
Boilers 3 and 4 to two separate turbines that generate 159 MW
each, and Boilers 5 and 6 to separate turbines that generate 139
and 144 MW. Total maximum continuous generating capacity of the
turbines is 601 MW. Each of the boilers is equipped with an
electrostatic precipitator (ESP), and each is served by a 214-ft
stack.
Additional unit design and operating data are presented in
Table 4-145. A site plan of the plant is shown in Figure 4-26.
4.16.2 Fuel Supply and Characteristics
The Ridgeland boilers fire oil and natural gas. Consumption
figures for 1975 show that the plant used approximately 4.42
million barrels of oil and 638 million cubic feet of natural gas.
Allied Oil Company, a division of Ashland Oil, Inc., supplied the
major portion of the fuel oil and Clark Oil Company the remain-
der. Tables 4-146 and 4-147 present fuel analyses and costs.
RIDGELAND POWER PLANT 4-211
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a
o
a
o
s:
§
TABLE 4-145- DESIGN AND OPERATING DATA FOR THE RIDGELAND POWER PLANT
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer13
Year placed in service
Max. coal consumption, tons/h
Max. heat inputc, 106 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
Coal firinga
1
79.5
6302
52.7
1
B&W
1951
42.7
769
213
384,000
385
ESP
2
79.5
5129
47.8
2
B&W
1951
42.7
769
213
384,000
385
ESP
3
79.5
7134
56.1
3
B&W
1950
42.7
769
213
384,000
385
ESP
4
79.5
6666
51.8
4
B&W
1950
42.7
769
213
384,000
385
ESP
5
144
3925
31.2
5
B&W
1953
74
1332
213
546,000
334
ESP
6
139
6012
49.8
6
B&W
1955
74
1332
213
546,000
334
ESP
^ a Information from Power Plant Survey Form (Appendix P)
• , y,^
M B&W - Babcock & Wilcox.
0 Based on coal heating value of 9000 Btu/lb.
-------
D
g
tr1
i
w
r
PARKING AREA
RID6ELAMD ^J
POWER PLANT V
r~
X
r i
1 !
i !
X
1
SWITCHYARD 1
§
UJ
00
-10
£20
o30
| *O
M
§50
g
60
1
t
4
•»
J
\
»
\
N)
H
U>
oo
o
OIL TANKS
Figure 4-26. Site plan of the Ridgeland power plant
-------
TABLE 4-146. ANALYSES OF FUEL USED AT THE RIDGELAND POWER PLANT
Analysis
Heating value
Sulfur
Oil3
147,886 Btu/gal
0.8%
Natural gas
1,034 Btu/ft3
Information from Power Plant Survey Form (Appendix P).
TABLE 4-147. COSTS OF FUEL AT THE RIDGELAND POWER PLANT
Fuel cost,a $/10 Btu
Type of Purchase
Contract
Firm
Oil
1.989
Natural gas
2.034
Information from Electrical Week magazine, December 1977.
4.16.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 067
as Priority I with respect to emissions of particulates and
sulfur oxides. Current Illinois regulations limit particulate
emissions to 0.10 lb/10 Btu from solid and liquid fuel firing
[Cook County Ordinance 6.2-2(b)]. Sulfur dioxide regulations
limit emissions to 1.0 lb/10 Btu from liquid fuel firing and 1.8
lb/10 Btu for solid fuel firing [Cook County Ordinance 6.3-
l(d) (2) (i)].
Table 4-148 summarizes current emission rates and applicable
regulations at the Ridgeland plant.
RIDGELAND POWER PLANT
4-214
-------
TABLE 4-148. EMISSION RATES AND APPLICABLE REGULATIONS FOR
CURRENT FUEL USAGE AT THE RIDGELAND POWER PLANT
Fuel type
BOILER 1
Current fuel
Oil
Gas
BOILER 2
Current fuel
Oil
Gas
BOILER 3
Current fuel
Oil
Gas
BOILER 4
Current fuel
Oil
Gas
BOILER 5
Current fuel
Oil
Gas
BOILER 6
Current fuel
Oil
Gas
Sulfur dioxide
Actual
emission rater
lb/106^ Btu
0.86
0.0006
0.86
0.0006
0.86
0.0006
0.86
0.0006
0.86
0.0006
0.86
0.0006
tons/yrb
1628
<1
1628
<1
1988
<1
1988
<1
1600
<1
2975
<1
Allowable
emission rate
lb/106 Btu
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
tons/yrb
1,893
4
1,893
4
2,312
5
2,312
5
1,860
275
3,459
26
Particulate
Actual a
emission rate
lb/106 Btu
0.05
0.015
0.05
0.015
0.05
0.015
0.05
0.015
0.05
0.015
0.05
0.015
tons/yrb
103
<1
103
<1
125
<1
125
<1
100
4
187
<1
Allowable
emission rate
lb/106 Btu
0.10
0.10
tons/yrb
206
1
0.10 206
0.10
0.10
0.10
0.10
0.10
1
250
1
250
1
0.10 200
0.10
27
0.10 374
0.10
3
a Emissions are based on AP-42 emission factors; an oil analysis of 0.8* S and 147,886 Btu/gal; and a gas
heating value of 1000 Btu/ft3.
b Based on 1975 fuel consumption.
RIDGELAND POWER PLANT
4-215
-------
4.16.4 Plant Programs for Complying with Emission Regulations
Firing the current fuels, the Ridgeland power plant is in
compliance with particulate and SCU emission regulations. Com-
monwealth Edison has formulated no plans for compliance in the
event the Ridgeland plant is ordered to convert to coal firing.
4.16.5 Analysis of Coal Conversion Potential
Coal Availability --
Coal is available from mines in the Illinois Basin (Produc-
ing Districts 9, 10, and 11) and the Wyoming-Montana (Producing
Districts 19 and 22) areas. Surplus capacity at the mines in the
Illinois Basin area is limited; however, several of the larger
producers in that area have indicated that they could develop new
mining capacity in 3 to 5 years if demand warrants it. Several
producers in the Wyoming-Montana area indicate that they now have
surplus capacity, but some of it would be available for only a
few years, after which it has already been contractually com-
mitted. Some area producers, however, are planning mine expan-
sion and/or new mines that could be producing within the next 3
years.
Table 4-149 shows characteristics of coal available to the
Ridgeland plant.
TABLE 4-149. ANALYSES OF AVAILABLE COAL FOR THE
RIDGELAND POWER PLANT
Analysis
Heating value, Btu/lb
Sulfur, %
Ash, %
Illinois-western
Kentucky
10,500 - 11,500
3-4
8-14
Wyoming -Montana
9,600 - 8,200
0.3 - 0.4
4-6
Foster Associates, Inc. Present and Prospective Coal Supply to
the Ridgeland Plant - Commonwealth Edison Company. May 30,
1975.
RIDGELAND POWER PLANT
4-216
-------
The Ridgeland plant would receive its coal by barge. Coal
produced in Illinois would be loaded onto either the Illinois
Central, Chicago and Illinois Midland, or the Burlington-Northern
Railroad and be transferred to barges at the Commonwealth Edison
docks at Havanna, Illinois. Coal shipments from Montana and
Wyoming would originate on the Burlington-Northern Railroad for
transfer to barges at Havanna. The rail carriers and several
barge companies have indicated that such movement would entail no
major problems.
Table 4-150 shows delivered costs of coal produced in
Illinois and the Wyoming-Montana areas. All transportation costs
are based on the lowest rail tariff. The cost of coal from
Producing Districts 19 and 22 is based on Burlington-Northern
volume tariff. All barge costs are based on Valley Line Company
volume tariff.
TABLE 4-150. ESTIMATED DELIVERED COAL COSTS FOR THE
RIDGELAND POWER PLANT
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Rail
Barge
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/106 Btuc
Illinois
21.00
6.40
1.32
28.72
1.368a
1.508a'C
Wyoming-Montana
7.00
9.89
1.32
18.21
1.110b
1.223b'C •
Based on 10,500 Btu/lb coal.
Based on 8,200 Btu/lb coal.
Foster Associates values escalated to 1978 dollars.
RIDGELAND POWER PLANT
4-217
-------
Technical Factors Affecting Fuel Conversion—
Ridgeland boilers fired coal until they were converted to
oil/gas firing in 1970. Reconversion to coal firing would re-
quire repairing or replacing such items as coal moving and un-
loading equipment, conveyor belt system, breaker house, and
ash/slag handling equipment. Instruments, controls, and other
boiler-related items would also require modification. Common-
wealth Edison has estimated (in a letter to FEA) a cost of
$17,795,000 (1978 dollars) to refurbish the coal and ash handling
equipment and make the necessary boiler modifications. Table
4-151 presents fuel usage data on which these costs are based.
4.16.6 Analysis of Methods for Controlling SO., Emissions
Firing Low-sulfur Coal—
The Ridgeland power plant could meet the 1.8 lb/10 Btu S02
emission regulation by firing low-sulfur (0.4% S) coal from the
Wyoming-Montana coal area.
Flue Gas Desulfurization (FGD)—
A sodium solution regenerable and a limestone scrubbing
system are evaluated for control of S02 emissions at Ridgeland.
These systems would have to provide approximately 75.2 percent
SO? removal to meet the 1.8 lb/10 Btu regulation while firing
Illinois Basin coal (4.0% S and 10,500 Btu/lb).
The estimated capital cost of retrofitting the six Ridgeland
boilers with a sodium solution regenerable system is
$129,527,000 ($215.52/kW); this figure includes $17,795,000 for
coal conversion. The estimated annual operating cost (including
a fuel credit for switching from oil/gas firing to coal) is
$19,039,000 (7.73 mills/kWh). The estimated capital cost of a
limestone scrubbing system for the six boilers (including the
cost of conversion) is $95,123,000 ($158.27/kW). The estimated
annual operating cost (including a fuel credit and bottom/fly ash
and sludge trucking costs) is $18,033,000 (7.32 mills/kWh).
All FGD costs are in January 1978 dollars and are not
escalated through project completion.
RIDGELAND POWER PLANT 4-218
-------
TABLE 4-151. COAL CONVERSION DATA FOR THE RIDGELAND POWER PLANT
Boiler
No.
1
2
3
4
5
6
Total
Capacity
factor
(1975) ,
%
52.7
47.8
56.1
51.8
31.2
49.8
Fuel consumption
Type
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Quantity/yr
1,219,300 bbl
17,600 103 ft3
1,488,600 bbl
20,300 103 ft3
599,200 bbl
548,800 103 ft3
1,113,800 bbl
51,200 103 ft3
Coal conversion data
Conv. cost,
$
17,795,000°
Coal usage,0
tons/yr
206,000
206,000
222,000
222,000
231,000
358,000
1,445,000
H
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M
VD
Quantities shown for Boiler 1 represent consumption for Boilers 1 and 2.
Quantities shown for Boiler 3 represent consumption for Boilers 3 and 4.
Represents coal required for conversion to total coal firing, based on average
coal heat rate.
Represents cost for entire plant.
-------
4.16.7 Analysis of Methods for Controlling Particulate Emissions
Boilers 1 through 4 at Ridgeland are equipped with ESP's
with design efficiencies of 98 percent, and Boilers 5 and 6 have
ESP's with design efficiencies of 90 percent. Calculations
(based on the ESP plate areas, air flows to be treated, and
migration velocities) indicate that none of the ESP's would have
actual efficiencies greater than 58 percent when firing low-
sulfur (0.4%) coal from Wyoming-Montana. Therefore, new ESP's
are evaluated on the basis of a collection efficiency of 86.4
percent, which is needed to bring the six boilers into compliance
with particulate emission regulations. Plate areas of 98,220 ft
are required for new ESP's on Boilers 1 through 4, and plate
areas of 139,660 ft for ESP's on Boilers 5 and 6.
The estimated capital cost of installing new ESP's on all
six boilers (including the cost of conversion) is $39,820,000
($66.26/kW). The estimated annual operating credit (including a
fuel credit and bottom/fly ash trucking costs) is $23,755,000
(9.64 mills/kWh).
The ESP costs are in January 1978 dollars and are not esca-
lated through project completion.
4.16.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the Ridgeland plant
to coal firing and complying with applicable SO- and particulate
emission limitations, the recommended strategy is to fire low-
sulfur coal from the Wyoming-Montana area and to install new
ESP's on all six boilers.
Table 4-152 summarizes the control methods evaluated for the
Ridgeland power plant. Table 4-153 presents estimated emission
rates and applicable regulations based on the recommended strategy.
RIDGELAND POWER PLANT 4-220
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a
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TABLE 4-152. ESTIMATED COSTS OF EMISSION OPTIONS
AT THE RIDGELAND POWER PLANT - 1978
Emission control alternative
Combined SOj/particulate control
Low-sulEur coal
Limestone scrubbing >c
Sodium solution regener-
ated
Particulate control
c d
ESP installation
Flue gas conditioning
Time
requi red
months
40
40
36
NA
Capital cost
106 S
SAW
Included be
95.12
129.53
39.82
158.27
215.52
66.26
Annualized cost
Fuel,
mills/kWh
OSM,
mills/kWh
.ow in ESP costs
(7.51)
(7.51)
(13.08)
7.44
4.57
1.34
Fixed,
mills/kWh
7.39
10.67
2.10
Total
mills/kWh
7.32
7.73
(9.64)
106 S
18.03
19.04
(23.76)
a Includes coal conversion cost of 517,795,000.
b System is based on coal analyzing 4.0% S, 12% ash, and 10,500 Btu/lb.
c Costs represent January 1978 dollars; they are not escalated through project completion, and they do not include
replacement power. Numbers in parentheses represent credits.
d System is based on coal analyzing 0.4% S, 6% ash, and 8,200 Btu/lb.
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TABLE 4-153. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE RIDGELAND POWER PLANT
w
z
o
13
o
s:
w
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t-3
fuel type
BOILER 1
Alternate fuel
Coald
BOILER 2
Alternate fuel
Coald
BOILER 3
Alternate fuel
Coald
BOILER 4
Alternate fuel
Coald
BOILER 5
Alternate fuel
Coald
BOILER 6
Alternate fuel
Coald
Sul fur d ioxidf a
Actujl 1 Allowable
emission rate I emission rjit_e
lb/106 Btu
0.93
(0.93)
0.93
(0.93)
0.93
(0.93)
0.93
(0.93)
0.93
(0.93)
0.93
(0.93)
tons/yr | ib/io6 Btu
1562
(1562)
1562
(1562)
1687
(1687)
1687
(1687)
1763
(1763)
2720
(2720)
1.8
1.8
1.8
1.8
1.8
1.8
tons/yrc
3023
3023
3265
3265
3412
5265
a
Po r [: i cu 1 J LC
Actua 1
emission rdtc-b
lb/106 Btu
0.10
(0.44)
0. 10
(0.44)
0. 10
(0.44)
0.10
(0.44)
0.10
(0.31)
0.10
(0.31)
tons/yr "~
168
(740)
168
(740)
182
(800)
182
(800)
190
(585)
293
(902)
A 1 lowcjbl c
fcii Si: jon rate
lb/10& Btu
0.10
0.10
0.10
0.10
0.10
0.10
tons/yrc
168
168
182
182
190
293
I
to
10
to
Numbers in parentheses indicate potential emissions resulting from conversion to total coal firing without
additional control equipment. Existing ESP efficiencies (using 0.4% S coal) are calculated to be approximately
40% for Boilers 1 through 4 and 58% for Boilers 5 and 6.
Based on emission factors.
Based on tons/yr of coal required for total conversion.
Emissions are based on coal analysis of 0.4% S, 6% ash, and 8,200 Btu/lb.
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4.17 RIVERTON PLANT
4.17.1 Plant Description
The Riverton power plant (owned by Potomac Edison Company)
is located on the Shenandoah River near Front Royal, Virginia.
This area is part of the Valley of Virginia Air Quality Control
Region (AQCR 226).
The plant consists of one Riley-Stoker boiler, which was
placed in service in 1949. The boiler has a generating capacity
of 40 MW and exhausts through a 130-ft stack. It is equipped
with a mechanical collector that has a design efficiency of 85
percent.
Additional unit design and operating data are presented in
Table 4-154, and a site plan is shown in Figure 4-27.
4.17.2 Fuel Supply and Characteristics
Since the middle of 1973, the Riverton boiler has been
firing residual fuel oil. In 1975, the boiler fired approxi-
mately 19,000 barrels of No. 2 fuel oil, which was supplied by
American Oil Company. Tables 4-155 and 4-156 present an analysis
of the fuel oil and its cost.
RIVERTON POWER PLANT 4-223
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TABLE 4-154. DESIGN AND OPERATING DATA FOR THE
RIVERTON POWER PLANT
Item
Coal firing'
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975), %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input0, 10 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
1
40
504
2.7
1
Riley
1949
27.2
675
130
212,000
360
Multiple-
cyclone
a Information from Power Plant Survey Form (Appendix Q).
b Riley - Riley Stoker Corporation.
C Based on coal heating value of 12,400 Btu/lb.
RIVERTON POWER PLANT
4-224
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A. CRUSHER HOUSE
B. TRUCK HOPPER
STORAGE
WASTEWATER
TREATMENT LAGOON
Figure 4-27. Site plan of the Riverton power plant.
RIVERTON POWER PLANT
4-225
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TABLE 4-155. ANALYSIS OF FUEL BURNED AT THE
RIVERTON POWER PLANT
Analysis
Heating value, Btu/gal
Sulfur, %
Fuel oil
138,335
0.21
Information from Power Plant Survey Form (Appendix Q).
TABLE 4-156. COST OF FUEL AT THE RIVERTON POWER PLANT
Type of purchase
Contract
Fuel cost,3 $/106 Btu
2.711
a Information from Electrical Week magazine, January 1978.
4.17.3 Atmospheric Emissions
The Environmental Protection Agency has classified AQCR 226
as Priority I with respect to particulate emissions, and Priority
II with respect to sulfur oxide emissions. Current Virginia
emission regulations applicable to all fuels are 0.20 lb/10 Btu
for particulates, and 2.64 lb/10 Btu for sulfur dioxides. High-
sulfur fuels can be fired if sulfur dioxide emissions are kept'
within the State's regulation.
Table 4-157 summarizes emission rates and regulations for
fuel currently fired at the Riverton power plant.
Air Quality Monitoring Data—
No ambient air quality data are available.
RIVERTON POWER PLANT 4-226
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TABLE 4-157. EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT
FUEL USAGE AT THE RIVERTON POWER PLANT
Fuel type
Boiler 1
Current fuel
Oil
Sulfur dioxide
Actual
emission rate
lb/106 Btu
0.238
tons/yr
15
Allowable
emission rate
lb/106 Btu
2.64
tons/yr
168
Particulate
Actual
emission rate
lb/106 Btu
0.0578
tons/yr
4
Allowable
emission rate
lb/106 Btu
0.20
tons/yr
14
3 Based on 1975 fuel oil usage, AP-42 emission factors, and an oil analysis of 138,335 Btu/gal
and 0.21% sulfur.
I
ro
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4.17.4 Plant Programs for Complying with Emission Regulations
Boiler 1 at the Riverton power plant is in compliance with
Virginia's emission regulations while burning fuel oil. Potomac
Edison Company has formulated no compliance plans in the event
the boiler is ordered to convert to coal firing.
4.17.5 Analysis of Coal Conversion Potential
Coal Availability --
Low-sulfur coal is available from southern West Virginia and
eastern Kentucky (Producing Districts 7 and 8). Coal producers
in these states have indicated that they currently have a surplus
of coal and can accommodate the future needs of the Riverton
power plant. Characteristics of coal from these producing dis-
tricts are shown in Table 4-158.
TABLE 4-158. ANALYSES OF COAL AVAILABLE TO THE
RIVERTON POWER PLANT
Analysis
Heating value, Btu/lb
Sulfur, %
Ash, %
Southern West Virginia and
eastern Kentucky
12,000 - 13,000
1.0 - 1.5
6-12
Coal would be transported to the Riverton plant by railroad.
The railroad siding on the plant site is in good condition and
can accommodate approximately 10 hopper cars per shipment. Coal
would be transported from the mines to the plant site first by
the Chessie System and then by the Norfolk and Western Railroad.
The Chessie System has indicated that its hopper car fleet could
handle the transportation of Riverton"s coal. Table 4-159 pre-
sents the delivered cost of low-sulfur coal.
Foster Associates, Inc. Present and Prospective Coal Supply to
the Riverton Plant - Allegheny Power Service Corp., an Agent of
Potomac Edison Company, June 18, 1976.
RIVERTON POWER PLANT
4-228
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TABLE 4-159.
ESTIMATED DELIVERED COAL COST FOR THE
RIVERTON POWER PLANT
Costs
Price (f.o.b. mine), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost,3 $/106 Btu
1978 total cost,3 $/106 Btu
Southern West Virginia and
eastern Kentucky
21.50
10.07
31.57
1.273
1.4031
Based on 12,400 Btu/lb coal.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Fuel Conversion—
The Riverton boiler burned coal for the first few months of
1973; most of the coal handling and firing equipment is still in
good working condition. Coal burners must be installed, however,
and fire protection equipment must be acquired. The plant also
needs a new stack, bulldozer, coal pile runoff facilities, and
ash pond. Conversion to coal firing would cost approximately
$2,269,000, and take about 36 months. Coal conversion data are
presented in Table 4-160.
4.17.6 Analysis of Methods for Controlling SO., Emissions
Low-sulfur Coal—
The Riverton power plant could meet Virginia's sulfur
dioxide regulation of 2.64 lb/106 Btu heat input by firing low-
sulfur coal (1.0 to 1.5 percent sulfur). Since complying-sulfur
coal is available to Riverton, no other methods for controlling
S02 emissions are evaluated (such as the sodium solution regen-
erable and limestone scrubbing systems).
RIVERTON POWER PLANT
4-229
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»
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TABLE 4-160. COAL CONVERSION DATA FOR THE RIVERTON POWER PLANT
Boiler
No.
1
Total
Capacity
factor
(1975),
%
2.7
Fuel consumption
Type
Oil
Quantity/yr
18,752 bbl
18,752 bbl
Coal conversion data
Conv. cost,k
$
2,269,000
2,269,000
Coal usage, ""
tons/yr
4,400
4,400
a Information from Power Plant Survey (Appendix Q).
b Based on a letter to the U.S. Environmental Protection Agency, May 5, 1977;
escalated to 1978 dollars.
c Additional coal required for total conversion to 100% coal firing.
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4.17.7 Analysis of Methods for Controlling Particulate Emissions
The current Virginia particulate emission regulation of 0.20
lb/10 Btu will require that an electrostatic precipitator (ESP)
be installed on Boiler 1 when it fires only coal. To meet the
particulate regulation if the boiler fired 1.0 percent sulfur
coal, the ESP would require a design efficiency of approximately
97.5 percent and a plate area of 87,000 ft .
The estimated capital cost of installing a new ESP is
$5,160,000 ($129.00/kW); this estimate includes a coal conversion
cost of $2,269,000. The annualized cost of operating an ESP on
Boiler 1 is $609,000 (64.37 mills/kWh), which includes a fuel
credit in switching from oil to coal firing.
4.17.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the Riverton plant
to coal firing, the recommended strategy is to burn low-sulfur
coal from Producing Districts 7 and 8 and to install a new ESP on
Boiler 1 to comply with applicable SO2 and particulate emission
regulations.
Table 4-161 summarizes capital and annualized costs for
control alternatives that were evaluated. Table 4-162 shows
emission rates and regulations based on the recommended strategy.
RIVERTON POWER PLANT 4-231
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TABLE 4-161. COST ASSESSMENT FOR EMISSION CONTROLS AT THE RIVERTON POWER PLANT - 1978
Emission control alternative
SO2 control
Low-sulfur coal
Limestone scrubbing
Sodium solution regenerable
Particulate control
Electrostatic precipitator
installation3 'b
Flue gas conditioning
Time
requ ired ,
months
NA
NA
36
NA
Capital cost
106 5
5.1G
S/kW
- Indue
129.00
Annualized Cost
Fuel ,
mills/kWh
ed in ESP ca
(15.01)
O&M,
mills/kWh
Iculations
19.66
Fixed,
mills/kWh
59.72
Total.
mills/kWh
64.37
106 $
0.609
a ESP design for Boiler 1 is Cor coal with an analysis of 1.0% sulfur, 11.0% ash, and 12,400 Btu/lb. Number in
parentheses represents a credit.
b costs are in January 1978 dollars, they have not been escalated through project completion and do not include
replacement power.
NA - Not available.
to
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TABLE 4-162. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE RIVERTON POWER PLANT
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to
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Fuel typo
Boiler 1
Alternate fuela
Coal
Sulfur dioxide
, Actual
emission rate
lh/in6 Btu
1.53
(1.53)
tons/yr
99
(99)
Al lowable
emission rate
lb/106 Btu
2.64
tons/yr
171
Particulate
Actual
emission rate
lb/106 Btu
0.20
(7.54)
tons/yr
14
(489)
Allowable
emission rate
lb/106 Btu
0.20
tons/yr
14
Based on 1975 operating data and a coal analysis of 1.0% sulfur, 11.0% ash, and 12,400 Btu/lb. Numbers
in parentheses indicate potential emissions resulting from a total' conversion to coal firing without
the installation of additional control equipment.
Ul
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4.18 VIENNA PLANT
4.18.1 Plant Description
The Vienna power plant of the Delmarva Power and Light
Company is located on the west bank of the Nanticoke River near
Vienna, Maryland. This area is part of the Eastern Shore Intra-
state Air Quality Control Region (AQCR 114).
The four Vienna boilers, numbered 5 through 8, were placed
in service in 1947, 1949, 1951, and 1971, respectively. Con-
tinuous generating capacities of the boilers (in the same order)
are 17, 17, 40, and 162 MW. Boilers 5 through 7 are served by
133-ft stacks; Boiler 8, by a 160-ft stack. Boilers 5 through 7
are Babcock & Wilcox units that can fire coal or oil without
derating; Boiler 8, a Combustion Engineering unit, can fire only
oil. Boilers 5 and 8 are equipped with mechanical collectors
with efficiencies of 60 and 87.5 percent. The mechanical sepa-
rator on Boiler 7 is now inoperative; however, with minimal work
it would have an estimated efficiency of 55.9 percent. Boiler 6
has no control equipment.
This report presents an evaluation o'f the coal conversion
potential of Boiler 7 only. Table 4-163 presents additional
design and operating data on this boiler, and Figure 4-28 shows a
site plan of the entire power plant.
4.18.2 Fuel Supply and Characteristics
The Vienna boilers have been firing residual oil since coal
burning was discontinued in 1971. In 1975, the plant fired
1,103,000 barrels of No. 6 fuel oil and 10,900 barrels of No. 2
fuel oil. Boiler 7 fired 138,000 barrels of No. 6 fuel oil.
Most of the fuel oil was supplied by Texaco, Steuart Petroleum,
and Paragon Oil. The latest available fuel oil analysis and fuel
oil costs are presented in Tables 4-164 and 4-165.
VIENNA POWER PLANT 4-234
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TABLE 4-163. DESIGN AND OPERATING DATA FOR THE VIENNA POWER PLANT
M
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01
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975)
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input,c 106 Btu/h
Stack height, ft above grade
Flue gas rate max., acfm
Flue gas temperature, °F
Emission controls
Coal firing
7
40
2490
15.3
6
B&W
1951
25.5
442
133
242,000
380
Mechanical
collector^
Information from Power Plant Survey Form (Appendix R).
B&W = Babcock and Wilcox.
0 Based on a heat rate of 11,045 Btu/kWh.
Inoperative.
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H
W
W-11. SLEEVE
FLOW
HAKTICOKE RIVER
Figure 4-28. Site plan of the Vienna power plant.
i
N)
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TABLE 4-164. ANALYSIS OF FUEL USED AT THE VIENNA POWER PLANT
Analyses
Heating value, Btu/gal
Sulfur, %
Fuel oil3
No. 2
137,656
0.2
No. 6
145,628
1.3
Information from Power Plant Survey Form (Appendix R).
TABLE 4-165. COST OF FUEL AT THE VIENNA POWER PLANT
Type of purchase
Spot
Fuel oil,a $/106 Btu
1.910
Information from Electrical Week magazine, May 8, 1978.
4.8.3 Atmospheric Emissions
The EPA has classified AQCR 114 as Priority I with respect
to emissions of sulfur oxides and particulates. Current Maryland
regulations limit particulate emissions to 0.3 lb/10 Btu heat
input for oil and coal. The regulations also limit the sulfur
content of oil and coal to 2.16 lb/10 Btu and 3.5 lb/10 Btu,
although higher-sulfur fuel can be fired if sulfur dioxide (S02)
emissions are controlled within the State regulations set forth
by the Air Pollution Control Board of Maryland.
Table 4-166 summarizes current emission rates and applicable
regulations for oil firing at the Vienna plant.
Air Quality Monitoring Data—
Ambient SO2 monitoring data collected at four stations in
the Vienna area in 1975 were used to characterize ambient air in
the vicinity of the Vienna power plant. All the measurements
VIENNA POWER PLANT
4-237
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TABLE 4-166. EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT
FUEL USAGE AT THE VIENNA POWER PLANT
Fuel type
BOILER 7
Current fuel
Oil
Suit Hi' dioxide:
Actual
omission i-ar.c
lb/106 Btu
1. 4
tons/yr
591
Al 1 owoblo
omission rate
lb/106 Btu
2.2
tons/yr
912
Par t icula te
Actual
omission rate
lb/106 Btu
0.055
tons/yr
23
Al lowable
omission rate
lb/106 Btu
0.3
tons/yr
127
a Based on actual 1975 fuel oil usage, AP-42 emission factors, and an oil analysis of 145,678 Btu/gal and 2.0% sulfur.
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indicated that Maryland S02 emission standards were met. The
maximum 24-hour average SO- concentration measured at the Vienna
3 3
plant (39 yg/m ) was far lower than the standard (262 yg/m ). No
information was provided on particulate emissions.
Table 4-167 presents Federal and State ambient air regula-
tions and ambient air monitoring data.
4.18.4 Plant Programs for Complying with Emission Regulations
Boiler 7 is now firing oil and is in compliance with partic-
ulate and SO- emission regulations. The Vienna plant has made no
compliance plans in the event they are ordered to switch to coal.
4.18.5 Analysis of Coal Conversion Potential
Coal Availability —
Although the Vienna plant has no current coal supplier, it
probably could obtain adequate supplies from former suppliers in
central Pennsylvania and northern West Virginia (Producing Dis-
tricts 1 and 3). Because current market conditions have created
surplus capacity at some mines, the plant might be able to meet
total coal requirements from current mine capacity. The duration
of this surplus capacity cannot be estimated, however, and condi-
tions could change before the plant is required to convert to
coal firing.
Coal from Producing Districts 1 and 3 would likely be trans-
ported by ConRail (formerly Penn Central) rail line. The only
major problem would involve upgrading the tracks on the plant
site. Delmarva Power and Light Company would have to purchase
hopper cars to get the coal to Vienna. Table 4-168 presents the
characteristics of coal from Producing Districts 1 and 3.
Foster Associates, Inc. Present and Prospective Coal Supply
to the Vienna Plant - Delmarva Power and Light Company.
June 18, 1976.
VIENNA POWER PLANT 4-239
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TABLE 4-167. COMPARISON OF FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
WITH THE MAXIMUM RECORDED VALUES NEAR THE VIENNA POWER PLANT
(Concentration in yg/m^)
Pollutant
Particulate
Annual geometric
mean
Maximum 24-hour
average
S02
Annual arithmetic
mean
Maximum 24-hour
average
Maximum 3-hour
average
Ambient Air Quality Standards
Federal
Primary
75
260
80
365
Secondary
60
150
1300
State
Primary
Secondary
75
160
79
262
Maximum
recorded
values
NA
NA
NA
39
NA
I
to
NA - Not available.
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TABLE 4-168. ANALYSIS OF AVAILABLE COAL FOR
THE VIENNA POWER PLANT
Analysis
Central Pennsylvania
northern West Virginia
Heating value
Sulfur
Ash
12,000 - 12,500 Btu/lb
2.0%
10 - 14%
Table 4-169 presents costs of delivered coal from producers
in central Pennsylvania. The f.o.b. mine prices represent cur-
rently quoted prices for contract purchases. Transportation
costs are based on current volume freight rates for 7000-ton coal
shipments to the Vienna plant, assuming restoration of rail
service.
TABLE .4-169. ESTIMATED DELIVERED COAL COSTS
FOR THE VIENNA POWER PLANT
Mine price, (f.o.b.), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btua
1978 total cost, $/106 Btua'b
Central Pennsylvania
northern West Virginia
18.00
7.37
25.37
1.015
1.119
Based on a coal with a heating value of 12,500 Btu/lb.
Foster Associates values escalated to 1978 dollars.
VIENNA POWER PLANT
4-241
-------
Technical Factors Affecting Fuel Conversion—
Delmarva Power and Light believes that an order to convert
Boiler 7 at the Vienna power plant to coal firing will entail
extensive work on their part to make the plant suitable. Company
officials indicate that the coal handling equipment, conveyors,
scales, pulverizers, crushers, fans, feed ducts, and controls
would need extensive maintenance or rebuilding. Because part of
the original coal storage area was taken for the addition of the
cooling towers and Boiler 8, a new area may be required. A new
ESP would be required for Boiler 7 to achieve compliance with the
State particulate regulation when firing coal. Because the
boiler is in a confined area, it would be necessary to locate the
ESP on the west side of the boiler house, which would entail long
and extensive duct runs and possibly a new stack. Bottom and fly
ash from coal firing probably would have to be trucked from the
site because regulations prohibit degrading the wetland area
across the Nanticoke River, where the Vienna plant ash pond is
now located. Since rail service to Vienna has been discontinued,
return to coal firing would require restoration of service by
ConRail and upgrading of the onsite tracks. Delmarva Power and
Light estimates the capital cost of converting Boiler 7 to be
approximately $446,000. Table 4-170 presents coal conversion
data.
4.18.6 Analysis of Methods for Controlling SO^ Emissions
Low-sulfur Coal--
The Vienna plant could meet Maryland's SO- regulation by
firing complying-sulfur coal (2.0% S) from central Pennsylvania
and northern West Virginia. Since this coal source is available
to the plant, flue gas desulfurization systems are not evaluated.
VIENNA POWER PLANT 4-242
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TABLE 4-170. COAL CONVERSION DATA FOR THE VIENNA POWER PLANT
Boiler
No.
7
Capacity
factor
(1975) ,
%
15.3
Fuel consumption3
Type
Oil
bbl/yr
138,000
Conv. cost,
$
446,000
_ , b
Coal usage,
tons/yr
22,000
Based on data in the 1975 FPC Form 67.
Additional coal required for conversion to 100% coal firing.
$300,000 reported by Delmarva in 1974; escalated to 1978 dollars.
I
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4.18.7 Analysis of Methods for Controlling Particulate Emissions
If the Vienna plant converts to coal, Boiler 7 will not be
in compliance with the particulate emission regulation; therefore
ESP control is evaluated. To achieve compliance, the new ESP
would require a collection efficiency of about 92.6 percent and
an estimated plate area of 48,940 ft . If low-sulfur coal is to
be burned, the estimated capital cost of such a unit is $3,602,000
($90.05/kW). The annual operating cost, including a fuel credit
resulting from switching from oil to coal firing, is estimated to
be $1,737,000 (32.40 mills/kWh).
4.18.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to coal
firing, PEDCo recommends the strategy of firing complying-sulfur
coal from Producing Districts 1 and 3 and installing a new ESP to
meet applicable SO? and particulate emission regulations.
Cost assessment for the recommended strategy is presented
in Table 4-171. Table 4-172 presents the emission rates and
regulations for the Vienna plant firing low-sulfur coal with a
new ESP.
VIENNA POWER PLANT 4-244
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TABLE 4-171.
COST ASSESSMENT FOR EMISSION CONTROLS AT THE
VIENNA POWER PLANT - 1978
Emission control
alternative
Combined SO2 control
Low-sulfur coal
Limestone scrubbing
Sodium solution
regenerable
Particulate control
Electrostatic precip-
itator installation13
Boiler 7
Flue gas conditioning
Time
required,
months
NA
NA
36
NA
Capital cost
S 106
3.602
S/kW
Inclu
90.05
Annualized cost3
Fuel ,
mills/kWh
3ed below ii
(18.60)
OHM,
mills/kWh
i ESP calci
39.49
Fixed ,
mills/kWh
lations
11.51
Total .
mills/kWh
32.40
$ 106
1.737
a Number in parentheses represents a credit.
b ESP design for Boiler 7 is based on firing coal with an analysis of 2.3 percent sulfur, 13.5 percent ash,
and 12,552 Btvj/lb.
c Costs are in January 1978 dollars; they have not been escalated through project completion; they do not
include replacement power.
NA - Not applicable.
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TABLE 4-172. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE VIENNA POWER PLANT
i-'uol typo
BOILEP. 7
Alternate fuel
Coal
Su 1 fur d iox idc
Actual
emission rato
lb/106 Btu
3.48
(3.48)
tons/yr
1030
(1030)
Al lowablc
em i ss ion rato
lh/106 Btu
3.5
tons/vr
1,036
Pa r t ioula te
Actual
omission rate
lb/106 Btu
0.3b .
(4.06)D
tons/yr
86bb
(1201)
Al lowable
em i ss ion ra te
lb/106 Btu
0.3
tons/yr
86
I
to
3 Based on 1975 operating data, boiler heat rate of 12,853 Btu/U/h, and a coal analysis of 2.3 percent sulfur, 13.5
percent ash and 12,552 Btu/lb. Numbers in parentheses indicate potential emissions resulting from a total conversion
to coal firing without the installation of additional control equipment.
b Based on 55.9 percent efficiency of existing mechanical collector.
OS
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4.19 WISDOM PLANT
4.19.1 Plant Description
The Wisdom power plant of the Corn Belt Power Cooperative is
located in Spencer, Clay County, Iowa. This area is part of the
Northwest Iowa Intrastate Air Quality Control Region (AQCR 090).
Wisdom has one Riley-Stoker front-firing, pulverized-coal
boiler, which was placed in commercial operation in 1960. The
boiler has a maximum continuous generating capacity of 38 MW and
can fire coal or natural gas without derating. The boiler is
equipped with a multicyclone mechanical collector and an electro-
static precipitator (ESP); their combined estimated efficiency is
99+ percent. The boiler exhausts through a 148-ft stack.
Table 4-173 presents additional unit design and operating
data; Figure 4-29 shows a site plan of the plant.
4.19.2 Fuel Supply and Characteristics
The primary fuel at Wisdom is 3 percent sulfur coal. Natu-
ral gas is fired as an auxiliary fuel during boiler startup and
as a supplement to achieve combustion stability. In 1975, the
plant fired approximately 42,870 tons of coal and 660.7 million
cubic feet of natural gas. Wisdom receives most of its coal from
the Welch Mine in Craig County, Oklahoma, and from Colstrip,
Montana. Tables 4-174 and 4-175 present the latest available
fuel analyses and fuel costs.
WISDOM POWER PLANT 4-247
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TABLE 4-173. DESIGN AND OPERATING DATA FOR
THE WISDOM POWER PLANT
Item
Coal firing'
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) ,
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input, 106 Btu/hb
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
1
38
8,163
47.0
1
Riley-Stoker
1960
18
433
148
180,000
350
Mechanical
collector
and ESP
Information from Power Plant Survey Form (Appendix S)
Based on 12,015 Btu/lb coal.
WISDOM POWER PLANT
4-248
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NATURAL GAS METERING AND
REGULATOR STATION
en
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SWITCHYARDI
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VO
Figure 4-29. Site plan of the Wisdom power plant,
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TABLE 4-174. ANALYSES OF FUEL USED AT THE
WISDOM POWER PLANT
Analysis
Heating value
Sulfur
Ash
Coala
12,015 Btu/lb
3.0%
11.6%
Natural gas
1000 Btu/ft3
Information from Power Plant Survey Form (Appendix S).
TABLE 4-175. COST OF FUEL FOR WISDOM PLANT
Type of purchase
Spot
Interruptible
Cost,
1.352
1.235
$/106 Btu
(coal)a
(Natural gas)
a July 1975 FPC Form 423 escalated to 1978 dollars.
From Electrical Week magazine, March 1977, price paid for
gas at Humbolt plant of Corn Belt Power Cooperative.
•
4.19.3 Atmospheric Emissions
The Environmental Protection Agency (EPA) has classified
AQCR 090 as Priority III with respect to emissions of particu-
lates and sulfur oxides.
Section 4.3(2b)(l) of the Iowa Regulations limits particulate
emissions to 0.80 lb/10 Btu heat input. Section 4.3(3a) limits
sulfur dioxide (SO9) emissions to 6.0 lb/10 Btu heat input if
6
solid fuel is burned and 2.5 lb/10 Btu heat input if liquid fuel
is burned. Table 4-176 summarizes emission rates and regulations
for the fuel currently fired at the Wisdom power plant.
Air Quality Monitoring Data--
No ambient SO- or particulate monitoring data are available
for the Wisdom plant. Table 4-177 summarizes State and Federal
ambient air regulations for the plant.
WISDOM POWER PLANT
4-250
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en
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TABLE 4-176. EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT FUEL
USAGE AT THE WISDOM POWER PLANT
Fuel type
BOILER 1
Current fuel
Coalb
Sulfur dioxide
Actual
emission rate
Ib/lo5 Btu
4.7
tons/yr
2,444
Allowable
emission rates
lb/106 Btu
6.0
tons/yr
3,120
Particulate
Actual
emission ratea
lb/106 Btu
0.0109
tons/yr
5.6
Allowable
emission rates
lb/106 Btu
0.8
tons/yr
411
Based on stack tests conducted by STW Testina, Inc., at 38 MW.
Based on coal analysis of 3.0 percent S, 11.6 percent ash, 12,015 Btu/lb and emission factors from AP-42, and from 1975
coal usage.
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TABLE 4-177. FEDERAL AND STATE AMBIENT AIR QUALITY STANDARDS
FOR THE WISDOM POWER PLANT
(Concentration in ug/m )
Pollutant
Particulates
Annual geometric
mean
24-hour maximum
so2
Annual arithmetic
mean
2 4 -hour maximum
3 -hour maximum
Ambient Air Quality Standards
Federal
Primary
75
260
80
365
Secondary
60
150
1,300
State
Primary
75
260
80
365
Secondary
60
150
1,300
Maximum
recorded
valuesa
tr1
»-3
No data available.
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4.19.4 Plant Programs for Complying with Emission Regulations
The Wisdom plant is in compliance with SCU and particulate
emission regulations while firing the current coal as the primary
fuel and is expected to remain in compliance if ordered to 100
percent coal firing.
4.19.5 Analysis of Coal Conversion Potential
Coal Availability —
The coal burned at the Wisdom plant is purchased from vari-
ous producers in southeastern Kansas and northwestern Oklahoma
(Producing District 15), southern Illinois (Producing District
10), and western Kentucky (Producing District 9). Some western
coal from Montana (Producing District 22) is also purchased to
blend with the high-sulfur Midwestern coals. Corn Belt Power
Cooperative is considering a 3- to 5-year contract to meet future
requirements of the plant. The source of the coal will be mines
in southern Iowa (Producing District 12). University Avenue Coal
Company, the major sales agent for Iowa coal, reports that sur-
plus capacity is sufficient to supply the Wisdom plant. Corn
Belt Power also plans to purchase Montana coal to blend with the
high-sulfur Iowa coal to enable the plant to remain in compliance
with the S02 emission regulations when noncomplying coal is
received. Small tonnages are readily available from Peabody Coal
Company and other Montana producers. Table 4-178 presents typi-
cal coal analyses of the Iowa and Montana coals.
Foster Associates, Inc. Present and Prospective Coal Supply
to the Wisdom Plant - Corn Belt Power Cooperative. June 18,
1976.
WISDOM POWER PLANT 4-253
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TABLE 4-178. ANALYSES OF AVAILABLE COAL FOR
THE WISDOM POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Iowa
(Producing
District 12)
10,100
3.1
15.0
Montana
(Producing
District 22)
8,450
0.75
10.4
The Wisdom plant is located on a spur from the Chicago,
Milwaukee, St. Paul and Pacific Railroad. Although the spur is
in poor condition, it is adequate to handle the coal requirements
of the plant. Businesses located on this spur are considering a
loan to the railroad to upgrade the spur. Coal produced in
Monroe County, Iowa, would originate on Burlington Northern and
would be transferred to the Chicago and North Western Railway at
Des Moines for delivery to Spencer, Iowa. Available hopper cars
have sufficient capacity to haul the additional coal requirements
of the Wisdom plant. Table 4-179 shows estimated costs of de-
livered coal.
TABLE 4-179. ESTIMATED DELIVERED COAL COSTS FOR
THE WISDOM POWER PLANT
Mine price, (f.o.b.), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $/106 Btu
Iowa
(Producing
District 12)
17.16
5.93
23.09
1.1433
1.260a'C
Montana
(Producing
District 22)
7.15
15.63
22.78
1.348b
1.485b'C
Based on a coal with a heating value of 10,100 Btu/lb.
Based on a coal with a heating value of 8,450 Btu/lb.
Foster Associates values escalated to 1978 dollars.
WISDOM POWER PLANT
4-254
-------
Technical Factors Affecting Fuel Conversion—
Since the Wisdom plant is now firing coal on a regular
basis, no coal handling or coal firing equipment is needed. To
fire 100 percent coal continuously throughout the year, however,
will necessitate additional sludge handling and wastewater treat-
ment equipment. PEDCo estimates this additional equipment will
cost $144,000. Table 4-180 presents fuel usage data on which
these costs are based.
4.19.6 Analysis of Methods for Controlling SO., Emissions
Low-sulfur Coal—
The Wisdom plant is now in compliance with the SO- emission
6
regulations (6.0 lb/10 Btu heat input) when firing coal. To
remain in compliance will require burning a 3.1 percent sulfur
coal with a heat content of 10,000 Btu/lb. This can be accom-
plished by obtaining coal from mines in southern Iowa (Producing
District 12) and blending it with low-sulfur Montana coal when it
exceeds the 3.1 percent sulfur. Because the plant is able to get
coal that meets the S02 regulation, flue gas desulfurization
systems are not evaluated.
4.19.7 Analysis of Methods for Controlling Particulate Emissions
The newly installed electrostatic precipitator (ESP) at
Wisdom was manufactured by American-Standard, Inc. The combined
efficiency of the ESP and the Hagen multicyclone mechanical
collector on the boiler is 99+ percent. Total plate area is
32,400 ft . The plant reports that the capital cost of this
equipment is $1.25 million. Stack tests conducted by STW Test-
ing, Inc., Denver, Colorado, on July 17, 1975, indicate that the
plant is in compliance with the particulate emission regulation
when firing its current coal at 38 MW (capacity rating). Testing
indicated an average potential emission rate of 0.0109 lb/106 Btu
of particulate. PEDCo estimates the net annual fuel cost result-
ing from firing 100 percent coal will be $360,000 (2.30 mills/kWh)
WISDOM POWER PLANT 4-255
-------
TABLE 4-180. COAL CONVERSION DATA FOR THE WISDOM POWER PLANT
Boiler
No.
1
Total
Capacity
factor
(1975),
%
47.0
Fuel consumption
Type
Coal
Gas
Quantity/yr3
42,870 tons
660.7 106 ft3
Coal conversion data
Conv. cost,
$
144,000
Coal usace,b/c
tond/yr
46,185
46,185
en
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2
t-3
Based on data obtained in 1975 FPC Form.
Based on 1975 capacity factors and 10,000 Btu/lb blended coal.
Additional coal required for conversion to 100 percent coal firing.
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4.19.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the plant to total
coal firing, the recommended strategy is to burn 3.1 percent
sulfur coal from southern Iowa and use low-sulfur Montana coal
for blending as required to meet the SO- emission regulation.
The newly installed ESP will enable the plant to comply with the
particulate emission regulation. Emission rates and regulations
applicable to the recommended strategy are shown in Table 4-181.
WISDOM POWER PLANT 4-257
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TABLE 4-181. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE WISDOM POWER PLANT
Fuel type
BOILER 1
Alternate fuel
Coal, 100%
Sulfur dioxide
Actual
emission rate3
lb/106 Btu
5.83
tons/yr
5,245
Allowable
emission rate
lb/106 Btu
6.0
tons/vr
5,398
Particulate
Actual
emission rate^
lb/106 Btu
0.015
tons/yr
13.5
Allowable
emission rate
lb/106 Btu
0.8
tons/yr
53
a Based on 3.1% sulfur, 15.0» ash, 10,100 Btu/lb coal and emission factors from AP-42. Tons/yr based on additional coal
required for 100» coal firing.
b Based on above coal analysis and stack test data.
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4.20 L. D. WRIGHT PLANT
4.20.1 Plant Description
The L. D. Wright power plant (owned and operated by the
Fremont Department of Utilities Company) is located in a residen-
tial-rural area on the edge of Fremont, Nebraska. This area is
part of the Nebraska Intrastate Air Quality Control Region (AQCR
146) .
The plant consists of three boilers: Boiler 6, a Babcock
and Wilcox unit installed in 1957, Boiler 7, an Erie City Iron
Works unit installed in 1963, and Boiler 8, a Babcock and Wilcox
unit installed in 1976. All are designed to fire coal and
natural gas. When firing 100 percent coal, their maximum contin-
uous generating capacities are 15, 20, and 91.5 MW, respectively,
3.5, 8.5, and 0.0 MW less than their combined natural gas and
coal ratings. Boilers 6 and 7 are served by separate 176-ft
stacks, and each is equipped with a single cyclone mechanical
collector with a design efficiency of 81 percent. Boiler 8 is
served by a separate stack and is equipped with an electrostatic
precipitator. Only Boilers 6 and 7 are being evaluated for 100
percent coal firing capabilities.
Table 4-182 presents additional unit design and operating
data, and Figure 4-30 presents a site plan of the plant.
4.20.2 Fuel Supply and Characteristics
The L. D. Wright plant is presently firing natural gas and
coal. Fuel consumption in 1975 was approximately 36,400 tons of
coal and 1,160 million cubic feet of natural gas. Tables 4-183
and 4-184 present analyses of the current fuels and cost data.
L. D. WRIGHT POWER PLANT 4-259
-------
TABLE 4-182. DESIGN AND OPERATING DATA FOR THE L. D. WRIGHT POWER PLANT
Item
Boiler number
Generating capacity, MW
Hours of operation (1975)
Average capacity factor (1975) , %
Served by Stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, tons/h
Max. heat input, c 10 Btu/h
Stack height, ft above grade
Max. flue gas rate, acfm
Flue gas temperature, °F
Emission controls
Coal firing
6
15
6,456
46
6
B&W
1957
8.3
171
176
66,100
275
Mechanical
collector
7
20
6,709
45
7
ERIG
1963
13.2
272
176
101,500
330
Mechanical
collector
o
•
s
jo
H
0
K
i-3
T3
O
S
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cn
o
a Information from Power Plant Survey Form (Appendix T).
b B&W - Babcock and Wilcox; ERIG - Erie City Iron Works.
c Based on a coal heating value of 10,300 Btu/lb.
-------
POWER PLANT
WATER
TREATMENT
BUILDING
WAREHOUSE
Figure 4-30. Site plan of the L.D. Wright power plant.
L. D. WRIGHT POWER PLANT
4-261
-------
TABLE 4-183. ANALYSES OF FUEL USED AT THE
L. D. WRIGHT POWER PLANT
Analysis
Heating value
Sulfur
Ash
Coala
10,300 Btu/lb
0.7%
7.0%
Natural gas
1,000 Btu/ft3
Information from Power Plant Survey Form (Appendix T).
TABLE 4-184. COST OF FUELS AT THE
L. D. WRIGHT POWER PLANT
Cost,3 $/106 BtU
Type of purchase
Spot
Firm
Coal
1.347
Natural gas
1.052
Information from Electrical Week magazine, May 22, 1978, for
the Nebraska Public Power District Company.
4.20.3 Atmospheric Emissions
The Environmental Protection Agency (EPA) has classified
AQCR 146 as Priority III with respect to emissions of particu-
lates and sulfur oxides. Current Nebraska regulations limit
particulate emissions to 0.8 lb/10 Btu heat input and sulfur
dioxide (SO2) emissions to 2.5 lb/10 Btu heat input for all
types of fuel. Table 4-185 summarizes applicable emission rates
and regulations.
Air Quality Monitoring Data—
No ambient particulate or S02 monitoring data are currently
available.
L. D. WRIGHT POWER PLANT
4-262
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F
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50
TABLE 4-185.
EMISSION RATES AND APPLICABLE REGULATIONS FOR CURRENT FUEL
USAGE AT THE L. D. WRIGHT POWER PLANT
^====^==
Fuel type
BOILER 6
Current fuel
Coala
Gasb
BOILER 7
Current fuel
Coal3
Gasb
Sulfur dioxide
Actual
emission rate
lb/106 Btu
1.29
0.0006
1.29
0.0006
tons/yr
208
<1
277
<1
Allowable
emission rates
lb/106 Btu
2.5
2.5
2.5
2.5
tons/yr
402
486
536
964
Particulate
Actual
emission rate
lb/106 Btu
1.33C
0.015
1.33C
0.015
tons/yr
213
3
284
6
Allowable
emission rates
lb/106 Btu
0.18d
0.18d
0.18d
0.18d
tons/yr
30
35
39
9
Based on 1975 coal consumption, AP-42 emission factors, and a coal analysis of 0.7% sulfur, 7.0% ash, and 10,300 Btu/lb
b Based on 1975 natural gas consumption, AP-42 emission factors, and a natural gas heat value of 1,000 Btu/ft .
c Mechanical collector efficiency estimated at 70%. 6
d This value assumes that Boiler 8 is in operation. Prior to Boiler 8 operation, the standard was 0.23 Ib SO2/10 Btu.
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4.20.4 Plant Programs for Complying with Emission Regulations
When firing low-sulfur coal and natural gas, the plant is in
compliance with the S02 emission regulation. The plant had a
particulate variance from the State of Nebraska until February 1,
1977, at which time the mechanical collectors on Boiler 6 and 7
were to be retrofitted with additional particulate control equip-
ment. The Fremont Department of Utilities has formulated no
compliance plans in the event the L. D. Wright plant is converted
to total coal firing.
4.20.5 Analysis of Coal Conversion Potential
Coal Availability —
Coal for the L. D. Wright plant is purchased from the Hanna,
Wyoming, area on the spot market. The Fremont Department of
Utilities is negotiating a long-term contract, under which the
coal for future plant requirements would come from a new under-
ground mine developed by Stansbury Coal Company in southwestern
Wyoming.
Two other possible sources of coal are being investigated.
Although some coal is currently available on a spot-purchase
basis in the Carbon County area of Wyoming, most mines in that
area are approaching full-capacity production with existing
reserves. Another possible coal source is in Jackson County,
Colorado. Table 4-186 presents typical coal analyses.
Foster Associates, Inc. Present and Prospective Coal Supply
to L. D. Wright Plant - Fremont Department of Utilities.
June 18, 1976.
L. D. WRIGHT POWER PLANT 4-264
-------
TABLE 4-186. ANALYSES OF AVAILABLE COAL
FOR THE L. D. WRIGHT POWER PLANT
Analysis
Heating value,
Btu/lb
Sulfur, %
Ash, %
Hanna,
Wyoming
10,300
0.7
7.0
Carbon County,
Wyoming
10,500
0.2 - 0.4
4.0
Jackson County,
Colorado
11,000
0.2
5.0
The L. D. Wright plant is located on the Chicago and North-
western rail lines. The new coal-fired generating capacity
recently added at the plant will require approximately 200,000
tons of coal per year. An additional 49,000 tons for total coal
firing would present no problems for the existing rail facilities,
All coal supplies evaluated for the L. D. Wright plant would
be loaded onto the Union Pacific Railroad at the source and would
be transferred to the Chicago and Northwestern at Fremont,
Nebraska, for delivery to the plant. The Union Pacific currently
has surplus hopper car capacity, and 715 hopper cars are on order
(to be delivered during the coming year). Discussions with the
railroad indicate that Union Pacific is well prepared to handle
considerable increases in coal traffic in the near future. If
additional hoppers are needed, the approximate lead time for
necessary construction is 12 to 18 months. Table 4-187 presents
the estimated costs of delivered coal.
L. D. WRIGHT POWER PLANT
4-265
-------
TABLE 4-187. ESTIMATED DELIVERED COAL COSTS FOR THE
L. D. WRIGHT POWER PLANT
Mine price (f.o.b.), $/ton
Transportation cost, $/ton
Total cost, $/ton
Total cost, $/106 Btu
1978 total cost, $106 Btu
Hanna,
Wyoming
17.00
9.05
26.05
1.240a
1.366a'C
Carbon
County,
Wyoming
14.00
9.17
23.17
1.103a
1.216a/C
Jackson
County,
Colorado
19.00
11.71
30.71
1.396b
1.538b'C
Based on a coal with a heating value of 10,500 Btu/lb.
Based on a coal with a heating value of 11,000 Btu/lb.
Foster Associates values escalated to 1978 dollars.
Technical Factors Affecting Fuel Conversion—
To convert the L.D. Wright plant to 100 percent coal firing
would require the modification or upgrading of some coal handling
equipment. The coal crusher, conveyors, and pulverizers must
be repaired, a new ash pond and coal loader must be installed,
and the size of the railroad siding must be increased. A waste-
water treatment center also will be required. PEDCo estimates
the total conversion cost to be $475,000. Table 4-188 presents
fuel usage data on which these costs are based.
4.20.6 Analysis of Methods for Controlling S02 Emissions
Low-sulfur Coal—
The L. D. Wright power plant could meet Nebraska's S0»
emission regulation (2.5 lb/106 Btu) by firing 0.7 percent sulfur
coal. Since this coal is available to the plant, flue gas desul-
furization systems are not evaluated.
L. D. WRIGHT POWER PLANT
4-266
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t-1
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a
TABLE 4-188. COAL CONVERSION DATA FOR THE L. D. WRIGHT POWER PLANT
Boiler
No.
6
7
Total
Capacity
factor
(1975) ,
%
46
45
Fuel consumption3
Type
Coal
Gas
Coal
Gas
Quantity /yr
15,600 tons
388.4 106 ft3
20,800 tons
771.129 106 ft3
Coal conversion data w
Conv. cost,
$
475,000°
Coal usage,"
tons/yr
17,400
31,200
48,600
1975 fuel consumption figures from Power Plant Survey Form (Appendix T).
Additional coal required for total conversion to 100 percent coal firing.
Cost for the entire plant for conversion to coal firing, no boiler breakdown
available.
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4.20.7 Analysis of Methods for Controlling Particulate Emissions
The design efficiency (81%) of the mechanical collectors now
installed on Boilers 6 and 7 is not sufficient to meet the par-
ticulate emissions regulation when the boilers are firing coal.
To be able to comply with this regulation, each boiler must be
equipped with an electrostatic precipitator (ESP) with a design
efficiency of 96.9 percent. Required plate areas for ESP's on
Boilers 6 and 7 are 28,500 and 43,800 square feet. Capital cost
for installation of appropriate ESP's is estimated to be $4,730,000
($135.14/kW), which includes a cost of $475,000 for coal conver-
sion. Annual operating cost is estimated to be $1,214,000 (8.70
mills/kWh), which includes a fuel cost differential resulting
from a switch to 100 percent coal firing.
4.20.8 Recommended Coal Conversion/Compliance Strategy
Of the available options for converting the L. D. Wright
plant to coal firing, the recommended strategy is to fire low-
sulfur coal to comply with S02 regulations and to install new
ESP's on Boilers 6 and 7 to comply with particulate emission
regulations. Table 4-189 presents estimated costs of the recom-
mended strategy. Table 4-190 presents estimated emission rates
and applicable regulations after the recommended strategy has
been applied.
L. D. WRIGHT POWER PLANT 4-268
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TABLE 4-189. ESTIMATED COSTS OF EMISSION CONTROL OPTIONS
AT THE L. D. WRIGHT POWER PLANT - 1978
Emission control
alternative
S02 control
Low-sulfur coal
Limestone scrubbing
Sodium solution
regenerable
Particulate control
Electrostatic precipitator instal-
lation on Boilers 6 and 7a'°
Flue gas conditioning
Time
required,
months
NA
NA
36
NA
Capital cost
106 $
4.730
S/kW
Incluc
135.14
Annual Coat
Fuel,
mills/kWh
Jed in ESP
0.84
O&H,
mills/kWh
calculations
2.84
Fixed,
mills/kWh
below
5.00
Total
mills/kWh
8.70
100 $
1.214
H
o
O
s
w
a ESP design for Boilers 6 and 7 is based on coal with an analysis of 0.7% S, 7» aah, and 10,300 Btu/lb.
b Costs are in January 1978 dollars; they have not been escalated through project completion; they do not. include replacement
power.
NA - Not applicable.
4*
I
N)
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13
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TABLE 4-190. EMISSION RATES AND REGULATIONS USING THE RECOMMENDED COAL
CONVERSION/COMPLIANCE STRATEGY AT THE L. D. WRIGHT POWER PLANT
Fuel type
BOILER 6
Alternate fuel
Coal3
BOILER 7
Alternate fuel
Coala
Sulfur dioxide
Actual
emission rate
lb/106 Btu
1.29
(1.29)
1.29
(1.29)
tons/yr
465
1465)
625.1
(625.1)
Allowable
emission rate
lb/106 Btu
2.5
2.5
tons/yr
906
1,202.5
Particulate
Actual
emission rate
lb/106 Btu
0.18
(1.33)b
0.18 .
(1.33)b
tons/yr
65
(480)
86.6
(637.5)
Allowable
emission rate
lb/106 Btu
0.18°
0.18C
tona/yp
65
86.6
a Based on 1975 operating data and a coal analysis of 70» sulfur, 7.0% ash, and 10,300 Btu/lb. Numbers in parentheses
indicate potential emissions resulting from a total conversion to coal firing without the installation of additional
control equipment.
b Mechanical collector efficiency estimated at 70».
c 0.18 Ib SO /106 Btu rate assumes that Boiler 8 is in operation. Prior to Boiler 8 operation, the standard was 0.23
Ib S02/10° Btu.
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